Docstoc

Comment on issues arising from t

Document Sample
Comment on issues arising from t Powered By Docstoc
					Comment on issues arising from the Victorian
Electricity Distribution Price Review 2006-2010




                                           A submission to the
                     Essential Service Commission on behalf of:

                                       Australian Industry Group
                                           Energy Action Group
                          Energy Users’ Association of Australia
                                              St Vincent De Paul
                              Victorian Council of Social Service
        Victorian Employers’ Chamber of Commerce and Industry




                                              Final: 16 May 2005
TABLE OF CONTENTS



                                                                                                                                   Page



Summary .................................................................................................................................. i

1.     Introduction ..................................................................................................................... 1

2.     Where are “efficiency gains” passed to consumers? ................................................ 3
       2.1.Forecasting of ‘efficient’ cost trends ........................................................................... 4
       2.2.Manifestations of the ‘efficiency incentive’.................................................................. 5
       2.3.The Impact of Related Party Transactions ................................................................. 6

3.     The Cost of Incentives. Do consumers benefit? ........................................................ 8
       3.1.The Impact of Strategic Behaviour ............................................................................. 9
       3.2.Issues for the ESC to explain ................................................................................... 10

4.     Weighted Average Cost of Capital .............................................................................. 15
       4.1.What the DBs want ................................................................................................... 16
       4.2.WACC and effective regulation................................................................................. 21
       4.3.Benchmarking........................................................................................................... 23
            4.3.1.. Comparison of cost of equity ........................................................................ 24
            4.3.2.. Comparison of the cost of debt..................................................................... 26
            4.3.3.. Comparison of Vanilla WACCs..................................................................... 27
       4.4.Individual Parameters ............................................................................................... 30
            4.4.1.. Market Risk Premium ................................................................................... 31
            4.4.2.. Risk-free rate ................................................................................................ 33
            4.4.3.. Equity Beta.................................................................................................... 34
       4.5.Choice of Model ........................................................................................................ 36
       4.6.Conclusion ................................................................................................................ 37

5.     Interval Meter Roll-out.................................................................................................. 40
       5.1.Interval Meter Costs.................................................................................................. 40
       5.2.Impact on consumers ............................................................................................... 44
       5.3.Problems with the DBs’ Response to the ESC Interval Metering Program.............. 47
       5.4.Improve the Tariff Reports ........................................................................................ 48

6.     Demand Management................................................................................................... 50
       6.1.DM – What is on offer? ............................................................................................. 50
       6.2.EUAA Demand Side Response Facility Trial............................................................ 52
            6.2.1.. Consumers want the positive incentives for action that DBs enjoy. ............. 53
            6.2.2.. DBs need clearer incentives to pursue demand management..................... 54
       6.3.Distributed Generation.............................................................................................. 55
       6.4.Approaches to providing incentives for demand management ................................ 56

Appendix A: DB Capex and Opex Performance............................................................... 59

Appendix B: WACC Comparisons ...................................................................................... 65
Acknowledgements:

This submission to the Essential Service Commission is made on behalf the Australian
Industry Group, Energy Action Group, Energy Users’ Association of Australia, St Vincent De
Paul, Victorian Council of Social Service, Victorian Employers’ Chamber of Commerce and
Industry.

The submission was prepared with the assistance of Marsden Jacob Associates (Dr Jeff
Washusen), whose contribution is gratefully acknowledged.

The submission has been supported by a grant from the National Electricity Consumers’
Advocacy Panel and their assistance is also gratefully acknowledged.

The views and interpretations expressed in this paper are those of the sponsoring consumer
groups.
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Summary
This submission comments on key issues for consumers arising from an analysis of
proposals submitted by the five Victorian electricity distribution businesses (DBs) and the
Essential Services Commission’s (ESC) Issues Paper - Electricity Distribution Price Review
2006-2010 and its subsequent Position Paper.

The resources provided to consumer groups to assist participation in the ESC’s review are
modest in comparison to those available to the DBs and the ESC. Accordingly, the report
focuses on a number of key issues that are judged to be of critical importance to, and will
impact on costs borne by consumers. No attempt has been made to deal with all issues
raised by the ESC.1

Issue 1:      Can the ESC demonstrate that efficiency gains will be transferred to
              consumers?

The ESC’s Position Paper acknowledges that the ‘approach developed by the ORG for the
2001-05 determination appears to have been remarkably successful’ (original emphasis).
There is no doubt that is correct. The DBs have earned substantially higher profits than
anticipated by ORG in 2000, while service standards targeted by ORG for ‘incentive’
payments have generally improved.

We have no doubt that the key issue for the ESC in this review is to demonstrate to
consumers how they will benefit from the efficiency gains that have obviously been achieved
by all DBs in the current regulatory period.

Ensuring consumers benefit from efficiency (as required by the Tariff Order and other
relevant Victorian legislation) is an essential tenet of the regulatory regime implemented by
ORG/ESC. Delivering to end-uses their share of the benefits the DBs have achieved will
require the ESC to demonstrate that it can deal with ‘strategic’ behaviour and ‘financial
engineering’ by the DBs - both of which are perfectly legal.

Failure by the ESC to clearly explain what the efficiency benefits are, how much they are
worth and to satisfy consumers that they will achieve these benefits would seriously
undermine consumer acceptance for continuing incentive regulation of energy utilities in
Victoria and possibly elsewhere.

It appears from the Issues Paper that the ESC understands this challenge. However, the
Position Paper appears to focus on the ESC’s concern about how best to ensure the profit
incentives in the regulatory framework do not lead to long-term degradation of asset
condition and service level. The Position Paper refers to concerns such as ‘the criticality of
infrastructure investment’ and the risk to infrastructure investment ‘arising from regulatory
processes that may be too short term in their focus.’

1
      It should also be noted that the dollar values quoted in this report are based on analysis of information
contained in the ESC’s Annual Performance Reports and the DBs’ submissions. The impact of discrepancies in
financial information contained in the DBs’ regulatory accounts or adjustments arising from application of the
ORG/ESC ‘efficiency carry-over mechanism’ have not been considered in this report and are not included in the
dollar values quoted. In addition, the Position Paper notes that the DBs have submitted revisions to their
original proposals, which are not taken into account in the values quoted in this paper. The dollar values may,
therefore, differ from comparable amounts quoted by the ESC in its papers.                                        E



                                                                                                         ES.i
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




End users would be extremely concerned if the ESC were to adopt an approach to regulation
based on the ‘campaign’ being run by regulated businesses and their lobbyists about a lack of
investment. Indeed, the ESC refers to the ‘strong incentive on the part of the distributors to
“talk up” future expenditure, and “talk down” future revenue’.

It is clear the DBs are attempting to exercise strategic behaviour by ramping up their forecast
costs way above levels they achieved over the last decade. They did the same thing in the
electricity distribution price review in 2000 and it paid them good dividends as the ORG was
prepared to provide them with significant Capex and Opex for the regulatory period now
ending (see comments below).

We believe it is absolutely essential for the ESC to demonstrate clearly that it can deliver a
fair and reasonable outcome from this review. The ESC must find a way to address this
without imposing further inefficient costs on consumers.

The preliminary analysis presented in this report, which is consistent with information
presented in the ESC’s Position Paper, shows that:

           ORG’s 2000 Decision (and subsequent Appeal) delivered between $75 and $150
           million/year in above benchmark revenue benefits to the DBs (that could total $500-
           600 million by the end of the current regulatory period);

           an additional benefit of some $330 million (Jun04) was achieved through the same
           mechanism in the 1996-2000 period; and

           the total efficiency benefits captured by the DBs, because actual costs were below
           the level adopted for (supposedly) efficient revenue building block cost
           benchmarks, are, at least –

                o    $215 million (Jun04) in the 1996-2000 period for Opex costs alone (noting
                     that Capex efficiency gains were possibly modest because the DBs invested
                     more than forecast in the last 2 years of this period); and

                o    Opex efficiency gains of between $45 million and $60 million/year have
                     been achieved in the first three years of the current regulatory period
                     (ignoring any additional benefit accrued by AGL, Citipower/Powercor and
                     United Energy through the Related Party arrangements identified by the
                     ESC).

                o    Capex efficiency gains in the current regulatory period are more difficult to
                     estimate, but an indicative figure would appear to be in the range of $10-20
                     million per year.

That is, cumulative benefits above efficient cost and efficient revenues that have been
captured by the DBs since 1996 appear likely to exceed $1.3 billion by the end of the current
regulatory period. This is equivalent to about 10% of the total cost of distribution services
paid by consumers.

The ORG/ESC ‘efficiency carry-over mechanism’ implemented in 2001 allows the
efficiency benefits captured in the current regulatory period to accrue to the DBs through to
2010. This same mechanism is meant to deliver all of the efficiency benefits to consumers
                                                                                                     E



                                                                                            ES.ii
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




after 5 years. The ESC must ensure this happens – and is seen to happen. The ESC must
clearly specify and set out the nature and amount of the efficiency gain in its determination
and show how this will be returned to consumers.

Issue 2:        Can the ESC demonstrate that it is capable of dealing with the DBs’
                strategic behaviour?

It is notable that even in the first year of the current regulatory period, the DBs benefited by
achieving a revenue outcome nearly $70 million above the efficient benchmark revenue set
only a month or so before the start of the year. In 1996, actual revenue was around $35
million above the (supposedly) efficient benchmark revenue set by Government. In fact,
actual revenue has exceeded efficient benchmark revenue every year since the DBs were
privatised.

The out-performance of revenue projections very early in a regulatory period suggests that
the DB forecasts of sales volumes were excessively conservative. If the DBs forecast lower
sales volumes, they are able to set higher unit prices and capture a benefit that is unrelated to
efficient operation. It is true that sales volume forecasts are uncertain, but robust forecasts
would be expected to be more accurate in the early years of the regulatory period. This has
manifestly not been the case and the possibility that the DBs are exercising strategic
behaviour in their forecasts must be addressed by the ESC.

There is no doubt, in Victoria at least, that the form of regulation implemented by ORG/ESC
works. Overall, the DBs continually out-perform (supposedly) efficient cost and revenue
benchmarks. However, as stated above, the incentive regulation articulated by ORG in its
2000 Decision, requires the efficiency benefits achieved by the DBs to be transferred to
consumers after no more than 5 years.

If this occurs – and can be verified to customers to their satisfaction – it would be a welcome
outcome and concrete benefit of incentive regulation. But it may not happen unless the ESC
applies its theory with rigour, clarity and determination.

The diagrams and analysis in the ESC Papers, and those presented in Sections 2 and 3 of this
submission,2 show that efficiency benefits embedded in the DBs’ revenue forecasts for the
next regulatory period are overwhelmed by clear strategic behaviour in forecasting increases
in both operation/maintenance and capital expenditure costs (or by excessive costs in
meeting technical and safety standards in the interval metering roll-out). The level of
forecast costs are totally unrecognisable compared to actual cost trends indicated over the
last decade.

Of particular concern are the forecast costs associated with the interval meter roll-out that
has been mandated by the ESC. The unit costs for this roll-out appear to be 5 to 6 times
higher per metering point than the much more functionally useful (e.g. communications and
load-control capable) metering roll-out that is underway in Italy. The DBs meter roll-out
costs also appear to be 2 to 3 times higher than the Ontario electric utilities own estimates for
a Victorian-scale interval meter roll-out (and the Ontario costs for interval meters appear to
be much higher than equivalent meters in Australia).



2
    See pp 3, 4 and 8.                                                                              E



                                                                                           ES.iii
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




We acknowledge that the Italian roll-out, which covers more then 30 million metering
points, will benefit from economies of scale that are unachievable in Australia. We also
acknowledge that electricity safety standards and occupational health and safety standards
are likely to increase the cost of meter replacements for some, possibly a significant number
of meter installations.

But it is inconceivable that economy of scale benefits would reduce unit costs by the amount
indicated by comparison between the DBs’ proposals and costs publicly reported by the
Italian company ENEL Distribuzione Spa and those attributed to the Ontario utilities. The
only possible conclusions are that technical and safety standards are adding excessively to
costs, which the ESC should examine closely, or that the DBs have excessively padded their
cost forecasts.3

Issue 3:      Why should Victorian DBs benefit from a higher cost of capital than allowed
              by all other jurisdictional regulators?

Another key issue for the ESC to explain to consumers is why it has been setting the
weighted average cost of capital (WACC) at the high end of the range established by
Australian regulators over the last decade. This outcome is imposing significant costs on
Victorian electricity users and providing a ‘regulatory windfall gains’ to the DBs for no
apparent reason. In the process, electricity prices in Victoria are higher then they should be
and the competitiveness of Victorian businesses is adversely impacted.

The ESC expresses no views in its Issues Paper on what the WACC should, or might, be for
the next regulatory period – despite the fact that all DBs have proposed that WACC should
be increased to even higher levels. Similarly, the ESC takes no firm position in its Position
Paper other than stating that there is ‘potential value transfer’ (from DBs to consumers)
from ‘the reduction in the real WACC’, but only because ‘real interest rates, as measured by
the prevailing yield on index linked government bonds (around 2.8 per cent), are lower now
than they were at the time of the 2001-05 price determination’.

The material in this report demonstrates that the ORG/ESC has been notably more generous
to regulated energy distributors than any other jurisdictional regulator – each of whom
openly acknowledge that they are being ‘cautious and/or conservative’ (i.e. giving energy
utilities the benefit of doubt on the value of WACC). The ESC has also set a much lower
WACC for Victoria’s water businesses, even though risk profiles would appear to be similar.
The material in this report also suggests that all Australian regulators are being excessively
cautious, and all could set WACC at lower levels without unsettling efficient capital
providers.

This needs clear explanation and justification by the ESC because its value of WACC
imposes very substantial costs on consumers - of at least $55 million/year4.




3
      This latter possibility cannot be proved conclusively from information in the public domain because the
level of disclosure of scope, timing, cost and numbers of complex installations is insufficient to replicate or test
the DBs’ proposals in any way. This is itself a cause for concern because of the large costs involved and the
DBs’ apparent disregard for the fact that their customers must pay for this.
4
      Total regulatory asset value times the difference in WACC values between ORG/ESC and other
jurisdictional regulators.                                                                                             E



                                                                                                             ES.iv
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Issue 4:      Dealing with Related Party Transactions and Service segregation.

We also note in particular that the ESC has raised concerns about the reliability of reported
financial information given the existence of Related Party arrangements entered into by
AGL, Citipower/Powercor and United Energy. There is no reason why the DBs’ owners
should not use this mechanism to control costs and stimulate fiscal discipline by DB
managers. But Related Party arrangements should not be used as an artifice to prevent real
efficiency gains being delivered to consumers as intended by the ORG/ESC efficiency carry-
over mechanism. The ESC needs to ensure that benefits are delivered to consumers and
preserve the integrity of the regime it administers.

In addition, the ESC’s Papers isolate metering costs for the current regulatory period and
deals separately with issues associated with Prescribed Services revenue and Excluded
Services revenue (which will include all metering costs from 2006).

We take on faith that the ESC is doing its best, in its Papers, to explain the complexity of
Related Party arrangements and metering costs to consumers, but the way these are handled
in the ESC’s Papers is confusing. For example, the estimates of Related Party ‘dilution’ of
reported efficiency gains is not transferred into the ESC analysis of DB proposed costs; and
insufficient detail is provided on metering costs in the current regulatory period to correlate
the ESC’s analysis with other information in the ESC’s public domain reports.

The ESC’s treatment of these matters may not impact on the end result, but it continues the
confusing way financial information and metering costs have been presented (or not
presented in the case of Excluded Service Charges and some specific metering costs) to
consumers in the ESC’s Performance Reports and the DB Annual Tariff Reports over the
current regulatory period.

Issue 5:      The cost and value to consumers of the interval meter roll-out.

The ESC’s treatment of the costs and benefits of the interval meter rollout is very confusing
– and the costs proposed by the DBs clearly excessive. The revised meter rollout costs
presented in the ESC Position Paper result in forecast (incremental) metering services
revenue growing for a total of $61.3M in 2006 up to $175.6M in 2010 (and $207M by 2012).
This translates into an incremental additional price impost between $5.22/year and
$54.26/year for single phase meters and could add up to 10% to a typical small consumer
bill.

It is difficult to understand why the DBs’ proposed interval metering costs are so high. The
total cost of the meter and installation is about 4 to 6 times the average total cost of the
ENEL roll-out in Italy, which not only includes an interval meter but also sophisticated two-
way powerline carrier communications technology with capability to offer interactive load
control, and the IT systems required to handle all the data.

The DBs meter roll-out costs also appear to be up to 3 times higher than the Ontario
Electricity Distributors’ Association estimates for a Victorian-scale interval meter roll-out of
800,000 meters over 3 years (and the Ontario costs include Stranded Asset recovery and
interval meters capital costs that appear much higher than equivalent meters in Australia).



                                                                                                   E



                                                                                          ES.v
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




The ENEL roll-out does offer opportunities to exploit economies of scale that could not be
achieved by any of the Victorian DBs, but it is inconceivable that a unit cost up to 600%
higher could be efficient even for a smaller scale roll-out.

It is also extremely disturbing that the ESC shows no inclination to consider roll-out of any
technologies that would allow consumers to access automatic, low-cost load control
technology that would assist them manage the cost impact of implementing time-of-use
tariffs that reflect the cost of increasing peak load. The ESC has rejected (an admittedly
inadequate) proposal by CitiPower and Powercor to undertake what appears to be a limited
roll-out of antiquated ripple control technology.

It is particularly disturbing that the ESC’s initial position is that: “No submissions indicated
that customers were (1) willing to have loads controlled by the distributor, and (2) prepared
to pay the additional cost for the “ripple control” technology. The ESC has, in fact,
received a number of submissions from consumer groups since 2000 suggesting that remote
load control should be examined closely. This is particularly because application of time-
of-use tariffs, similar to United Energy’s, will adversely impact large numbers of AC-using
consumers – something that the ESC should be aware of since this was the subject of a
submission made to the ESC on behalf of CUAC in 2003.

Without automatic load control capability, adversely affected consumers have few choices –
apart from denying themselves use of the ACs – if they wish to avoid substantially higher
bills. If this generates adverse consumer reaction, which is very likely, the ESC may be
moved to impose transitional arrangements or tariff design constraints on the DBs (and even
retailers) which will drag out achievement of the benefits of interval metering over even
longer time frames than already anticipated. This would be a very poor outcome for
consumers forced (by the ESC) to bear higher costs.

It is essential that the ESC closely scrutinise the costs of the proposed interval meter roll-out
and also closely examine how the impact of punitive cost-reflective time-of-use tariffs can be
managed.

Issue:        Incentives for demand management.

The ESC’s and the DBs’ proposals for demand management are totally unsatisfactory and
noticeably out of step with programs supported by both IPART and ESCoSA.

The Demand Side Response Facility Trial undertaken by the EUAA in late 2002 showed
conclusively that large end-users were interested in examining demand management
initiatives. The Trial also identified a number of major obstacles, including distorted
incentives in the Victoria regulatory regime for distributors, which need to be addressed.
While the Trial focussed solely on large industrial and commercial consumers, the outcomes
and the issues that the Trial identified are equally applicable to small consumers. Significant
progress has been in addressing some of these obstacles, but the ESC and DB proposals do
nothing at all to address obstacles in the Victorian regulatory regime.

The ESC would do well to follow the example of other, more progressive and consumer-
focussed, regulators such as IPART and ESCoSA on this issue. The ESC could do this by
developing a Demand Management Code that is similar to those adopted by IPART and
ESCoSA and also replicating the range of initiatives endorsed by ESCoSA that are to be
trialled by ETSA Utilities. These initiatives include:
                                                                                                    E



                                                                                           ES.vi
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        “power factor” improvements in business and manufacturing premises;
        trials of Voluntary Load Curtailment (VLC) programmes for large customers;
        Direct Load Control (DLC) of domestic equipment such as air-conditioners and pool
        pumps;
        use of standby generation, and
        the use of incentives for customers to reduce demand at times of peak demand.

These actions by IPART and ESCoSA shows that the ESC needs to provide some additional
‘positive’ incentives for DM as part of the next regulatory period. If it does not do this, the
ESC leaves itself open to the accusation that it is out-of-touch with the latest developments
in regulation, out-of-step with other regulators and out of touch with actions that could assist
in protecting the long-term interests of consumers. Victoria, which badly needs a more
active DM response to help it meet the challenge of growing peak demand, will be left more
exposed to the consequences, including unfettered growth in peak demand, higher Capex and
higher electricity costs.




                                                                                                   E



                                                                                         ES.vii
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




1. Introduction
Marsden Jacob Associates (MJA) has assisted a consortium of Victorian consumer groups
prepare this submission to the Essential Services Commission’s (ESC) review of
electricity distribution prices for the 2006-2010 period. The sponsoring consumer groups
are:
        Australian Industry Group (AiG)
        Energy Action Group (EAG)
        Energy Users Association of Australia (EUAA)
        St Vincent De Paul
        Victorian Council of Social Services (VCOSS)
        Victorian Employers’ Chamber of Commerce and Industry (VECCI)

The submission provides comment on key issues for consumers arising from analysis of
proposals submitted by the five Victorian electricity distribution businesses (DBs) and the
Essential Services Commission’s (ESC) Issues Paper - Electricity Distribution Price
Review 2006-2010. The comments have been developed following review of the DBs’
pricing proposals and the Issues Paper and Position Paper published by the ESC.

The resources provided to consumer groups to assist participation in the ESC’s review are
modest in comparison to those available to the DBs and the ESC. Accordingly, the
submission focuses on a number of key issues only. These issues are judged to be of
critical importance to, and will definitely impact on costs borne by, consumers. The
report provides commentary, analysis of data and information relating to five topics, viz.
the cost of the ‘efficiency incentive’ constructed by the ORG in 2000, the value (to the
DBs) of efficiency gains, the ORG/ESC approach to estimating the cost of capital, the
cost of interval meter roll-out and the DBs proposals for demand management.

Section 2 provides a brief overview of the approach used to prepare a preliminary
estimate of the cost to consumers of the efficiency incentive embedded in the Victorian
electricity distribution regulatory regime.5 This section also provides a brief commentary
on how the primary profit incentive works, which it clearly does, and makes the point
that, from a consumer’s perspective, the ESC has a clear role to play. The ESC must sort
out the impacts of strategic behaviour and ‘financial engineering’ (that is quite legal) by
the DBs, identify and quantify the value of the efficiency gains achieved over the current
regulatory period and ensure these are passed through to consumers as required by law
and intended by the ORG in its 2000 Decision.



5
      Dollar values quoted in this submission are based on analysis of information contained in the ESC’s
Annual Performance Reports and the DBs’ submissions. The impact of discrepancies in financial information
contained in the DBs’ regulatory accounts or adjustments arising from application of the ORG/ESC
‘efficiency carry-over mechanism’ have not been considered and are not included in the dollar values quoted.
In addition, the Position Paper notes that the DBs have submitted revisions to their original proposals, which
are not taken into account in the values quoted in this paper.
The dollar values may, therefore, differ from comparable amounts quoted by the ESC in its papers. However,
any difference in value is secondary to the importance of the impacts on consumers of the issues raised.



                                                                                                             1
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Section 3 provides a preliminary estimate of the value (to the DBs) of the efficiency gains
and raises questions for the ESC to address as to when an efficiency benefit becomes
monopoly rent.

Section 4 addresses issues associated with the ORG/ESC’s approach to estimating the
weighted average cost of capital (WACC). This is a particularly important issue that
requires clear explanation and justification by the ESC because of the cost it imposes on
consumers. The ESC stands out amongst jurisdictional regulators in adopting a
consistently higher value for WACC for energy utilities. Comment is also provided on
some of the more controversial matters connected with estimating WACC that suggest
the ESC (and all other Australian regulators) could reduce the value of WACC without
unsettling efficient providers of capital (who have reasonable expectations).

Section 5 provides a comment on preliminary analysis of the costs proposed by the DBs
for rolling out interval meters as mandated by the ESC and compares the cost of these
proposals with much lower cost metering roll-out programs underway in Italy and
Ontario.

Finally, Section 6 provides a very brief commentary, and extracted examples, of the DBs’
proposals so far as they may affect incentives for consumers to practice or offer demand
management or energy conservation.




                                                                                          2
        Victorian Consumers’ Groups
        VIC 2006 Electricity Distribution Price Review




        2. Where are “efficiency gains” passed
           to consumers?
        The diagrams below present a summary of analysis comparing forecast, approved and
        actual capital expenditure (Capex) and operations and maintenance expenditure (Opex)
        for the period from 1996.6 Costs are shown with and without the proposed interval meter
        roll-out, which allows direct comparison between the current and next regulatory periods.

        Rather than attempting to match the presentation of data in the ESC’s Papers, the
        comparisons of total cost (combining Prescribed and Excluded Service costs) use
        information from the DBs’ proposals and ORG/ESC public domain sources. This
        treatment of costs is simpler and more closely related to costs included in consumers’
        bills. For example, small consumers’ bills do not identify Prescribed and Excluded
        Service charges (or distribution, transmission and retail charges for that matter).

        It is acknowledged that this analysis cannot deal with the impact of related party
        transactions on reported efficiency gains. This is certain to mean the estimates of benefits
        accrued by the DBs since 1996 significantly understates those benefits. Nor is it possible
        to compare the costs from one period to the next unless the metering costs are included
        (or excluded) in both. The ESC has chosen to separate metering costs from Prescribed
        Service costs in the current regulatory period. The diagrams in this submission are based
        on combining (but showing separately) metering and non-metering costs.

        FIGURE 1: TOTAL CAPEX ($M JUNE 2004) WITH AND WITHOUT METERING

                                             Total CAPEX ($M Jun04 - With & w/o Metering)
$900
              Total CAPEX DB Forecast
              Total CAPEX (Excl Metering) DB Forecast
$800          Total CAPEX ORG
              Total CAPEX Actual                                       And this is:
              Linear (Total CAPEX Actual)                    ♥ "increased standards" (?);
$700                                                    ♥ "increased (metering) services" (?);
                                                                          and
                                                        ♥ increased "strategic behaviour" (or
                                                            confiscation of the consumer
$600                                                            "efficiency dividend")?



$500



$400

                                                                                                                  This the
                                                                                                                 "efficient"
$300
                                                                                                                CAPEX Trend!
                                                                              This is the
                                                                             "efficiency"
                                                                             incentive at
$200                                                                            work!



$100
       1996      1997     1998      1999     2000       2001      2002     2003      2004        2005   2006   2007   2008     2009       2010




        6
            All values in June 2004 dollars



                                                                                                                                      3
        Victorian Consumers’ Groups
        VIC 2006 Electricity Distribution Price Review




        FIGURE 2: TOTAL O&M ($M JUNE 2004) WITH AND WITHOUT METERING

                                             Total O&M ($M Jun04 - With & w/o Metering)
$600
                                                                      And this is:
              Total O&M DB Forecast
                                                            ♥ "increased standards" (?);
              Total O&M (Excl Metering) DB Forecast    ♥ "increased (metering) services" (?);
$550          Total O&M ORG                                              and
              Total O&M Actual                         ♥ increased "strategic behaviour" (or
              Linear (Total O&M Actual)                    confiscation of the consumer
                                                               "efficiency dividend")?
$500



$450



$400



$350


                                                                          This is the
$300                                                                     "efficiency"
                                                                         incentive at
                                                                            work!
                                                                                                             This the
$250                                                                                                    "efficient" OPEX
                                                                                                              Trend!

$200
       1996    1997      1998     1999     2000       2001    2002     2003      2004     2005   2006       2007    2008   2009       2010



        It is relevant to note that estimates have been included for some DBs’ forecast metering
        costs because only one DB provided full details of Capex, Opex, revenue projections and
        Excluded Service Charges for the metering components. The way information was
        presented by the DBs is confusing because the DBs followed the ESC’s proposal to leave
        the value of existing metering assets in the Prescribed Services regulated asset base, while
        all Capex for future metering are included in the Metering Excluded Service Charge.
        More confusion is created by including all Opex costs for all metering in the Prescribed
        Services cost base. This makes it impossible to directly compare the metering cost
        proposals for each DB, or to replicate/confirm the ESC’s analysis.


        2.1.       Forecasting of ‘efficient’ cost trends
        A simple linear regression applied to (reported) actual expenditure has been used to
        indicate the efficient cost trend for both Capex and Opex.7

        The ‘efficient cost trend line’ is indicated in the above diagrams by the dashed blue line.
        The difference between the actual costs and forecasts cost approved by ORG (or the
        Victorian Government prior to 2000) indicates how the efficiency incentive in the
        regulatory regime is intended to work.




        7
             It is pleasing to see the ESC compare forecast, approved and actual costs in its Papers; but it would be
        preferable if the ESC adopted a trend analysis approach similar to that shown in the diagrams in this report.
        The consumer groups’ submission to the 2001-2005 price review supported the econometric analysis methods
        used by UK regulators as early as 1994.



                                                                                                                                  4
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




2.2.        Manifestations of the ‘efficiency incentive’
The way in which the incentive works also provides some guidance as to the likely extent
of strategic behaviour by the DBs. There is some complexity in the different efficiency
valuations and the incentive for strategic behaviour. For example, the efficiency
incentive is valued differently for Capex and Opex:
        For Capex, the efficiency benefit is represented by the difference between forecast
        and actual Capex times the WACC plus the difference between forecast and actual
        Capex times the DB’s particular depreciation rate.
        This is relatively complex because the level of Capex investment (whether forecast
        or actual) is not directly recovered through regulated revenue on a dollar for dollar
        basis. Rather, the Capex is rolled into the regulatory asset base (RAB) and the cost
        recovered over more than one regulatory period through the regulatory revenue
        building blocks for return on capital (RAB x WACC) and return of capital
        (depreciation).
        There is an actual or potential conflict for the DBs to resolve with the Capex
        efficiency incentive:
        −     If a DB reduces Capex in, or delays investment beyond, any single regulatory
              period, it gets to keep the resulting Capex efficiency gain for a maximum of
              five years (through the efficiency carry-over mechanism implemented by
              ORG in 2000).
        −     However, a reduction in Capex reduces the value of RAB for the next
              regulatory period and reduces the revenue building block components for
              return on and return of capital (in the next regulatory period).
        −     If the DB delays the Capex into the next regulatory period, it faces a risk that
              the ESC may not allow reinstatement of the full value of deferred Capex in the
              next regulatory period on the basis that consumers have already paid once for
              (part of) the delayed Capex.8
        A rational response to this conflict (for the DBs) is to forecast higher Capex than a
        reasonable asset management planning process would suggest is required (a
        manifestation of strategic behaviour), then delay Capex as long as possible in the
        current regulatory period, but commit Capex on projects that cannot be avoided
        before the start of the next regulatory period.
        The impact of this rational response is inferred in the difference between forecast
        and actual Capex in the above diagram:
        −     Capex spending increased above the forecast amounts in the latter part of the
              1996-2000 period as DBs invested Capex that could no longer be avoided in
              response to high-profile adverse publicity about poor reliability performance;
        −     DBs forecast a significant increase in Capex in 2001, which ORG (and the
              Appeal Panel) generally accepted – even though it was clear to consumer


8
      The ESC should closely examine this issue. Any risk to the DBs would only arise if the ESC
successfully sorts out the influence of strategic behaviour in the forecasts and keeps a period-on-period track
of individual Capex components. The ESC Position Paper devotes attention to this very matter, but appears
more concerned about dealing with the risk that DBs might be running down their assets by under-investing
in maintaining service capability. Both matters need to be addressed.



                                                                                                              5
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




              groups at the time that the increase, most likely, contained a significant
              element of strategic behaviour that ORG was reluctant to discuss or consider;9
        −     actual Capex in 2001 was significantly below the approved forecast - and
              actuals immediately prior to 2001 – and declined further (below the approved
              forecast) in 2002 as the DBs sought to maximise the efficiency gain;
        −     actual Capex increased in 2003, although it remains well below the levels
              approved by ORG.
        For Opex, the efficiency benefit is much more obvious and the reaction by DBs
        more straight forward. Each dollar saved by a DB (the difference between forecast
        and actual Opex) goes straight onto the bottom line of the DB owner’s profit and
        loss statement (less tax, if tax is paid). Since there is no timing benefit in delaying
        Opex efficiency improvements, all (well-managed and profit-motivated) DBs
        would be expected to chase every possible Opex saving consistently throughout the
        regulatory period – and inflate their forecasts as high as they think they could
        possibly get away with.

The above diagrams consolidate all DBs’ Capex and Opex. Individual diagrams for each
DB are shown in Appendix A. It is notable that not all DB Capex and Opex trends show
the same characteristics. For example:10
        The above-forecast Capex spending in the 1996-2000 period was more obvious for
        AGLE (Solaris as it was then) and Powercor, whereas Citipower, TXU (Eastern
        Energy) and United Energy achieved actual expenditure closer to forecast.
        In 2000, AGLE, TXU and United forecast significant increases in Capex (that were
        generally endorsed by ORG/Appeal Panel), and all three subsequently underspent
        the forecasts; whereas Citipower and Powercor both forecast Capex similar to the
        1996-2000 period, and both subsequently reasonably closely matched their
        forecasts.
        All DBs apart from AGLE (Solaris) achieved significant reductions in Opex in the
        1996-2000 period; and all DBs put forward significantly increased forecasts (above
        actuals) that were subsequently reduced by ORG.
        All DBs apart from AGLE achieved significant reductions in Opex from 2001,
        although both TXU and United report increases in Opex to near-forecast levels in
        2003.


2.3.        The Impact of Related Party Transactions
As the ESC implies in its Papers, interpretation of these varied outcomes is complicated
by the related party arrangements entered into by AGLE (with Agility), Citipower and
Powercor (with each other) and United (with Alinta, United’s part-owner). Under these
related party arrangements, Capex and/or Opex services are being provided where the

9
     See comments in Office of the Regulator-General - 2001 Electricity Distribution Price Review,
Response to Draft Decision - A Consumer Perspective, Pareto Associates Pty Ltd Report for the Customer
Energy Coalition, July 2000.
10
      The observations of Capex differences for individual DBs is, most likely, distorted by the impact of
related party transactions where these transactions have the effect of retaining efficiency gains within the
related parties while actual are reported to match (or be close to) forecasts.



                                                                                                           6
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




costs of services are tied to the (supposedly) efficient cost benchmarks adopted by ORG
in 2000.

Related party arrangements are entirely legal and could even be a useful way for the DB
owners to impose fiscal discipline on DB managers. However, the ESC notes11 that these
arrangements may also allow the DB owners to capture the efficiency gains within
separate businesses that they control - while reporting to the ESC the costs paid by the
DB entity to the Related Party as actuals.

The ESC is correct in stating that such behaviour, even if entirely legal, is unsatisfactory
because, it prevents transparent disclosure of efficient costs. The routine disclosure of
efficient costs is a fundamental feature of the ORG/ESC’s regulatory framework.

The ESC’s Papers do not discuss in detail how the ESC is dealing with this challenge to
its regulatory framework, other to say “(w)ith the exception of TXU with whom full
agreement has been reached, discussions between the Commission and the distributors
are continuing. The key issues that remain outstanding are the treatment of related party
transactions and the allocation of IT assets (CitiPower).”12

One of the issues raised by the ESC is “whether the related parties of distributors should
be able to retain any efficiency gains through distributors being able to value their
contracts with such related parties at other than the total costs incurred by those related
parties in performing those contracts (including a reasonable allowance for profit), or
whether the gains should be returned to customers over time. If the gains should be
returned to customers, what proportion of them should be so returned, and over what
period of time?”13

From a consumer perspective, the answer to this question is simple. A fundamental tenet
of the regulatory regime is that consumers are to benefit from efficiency gains. The ORG
made a substantial concession to the DBs in 2000 by establishing the efficiency carry-
over mechanism to provide a (more-or-less) constant incentive for DBs to pursue
efficiency gains. The carry-over mechanism allows the DBs to retain the full value of the
efficiency gain for a 5 year period. An equally fundamental tenet of that regulatory
arrangement is that the long-term benefits of efficiency gains were to be transferred in
full to consumers after the 5 year period.

Related party arrangements may be legal. But, if the effect of these arrangements is to
deny benefits that were clearly intended to pass to consumers, then the ESC must act to
ensure the benefits are passed to consumers in full and in accordance with the law and the
intent of the efficiency carry-over mechanism. The DB owners would still get the full
benefit intended and offered in the ORG/ESC efficiency carry-over mechanism. But they
should not be permitted to use a legal or accounting artifice to prevent consumers from
obtaining benefits that the ESC is required by law to deliver to them.




11
     The ESC also refers to the fact that concern about the use of related party transactions had been raised
by the Productivity Commission.
12
     p 15, ESC Issues Paper.
13
     p 17, ESC Issues Paper.



                                                                                                            7
         Victorian Consumers’ Groups
         VIC 2006 Electricity Distribution Price Review




         3. The Cost of Incentives. Do
            consumers benefit?
         The diagram below shows a comparison between DB forecast, allowed and actual
         revenue. The DB forecasts are shown in red, with the solid red line representing forecasts
         that combine metering and tariff revenues and the dashed red line excluding (estimated)
         interval metering revenues post 2005. The actual DB revenue is shown as the blue line,
         with the drop in revenue from 2000 to 2001 showing the impact of ORG’s 2000
         Determination on actual revenues. The green lines represent ORG’s estimate of
         ‘efficient’ maximum allowable revenue for the current regulatory period.

         If one assumes that the ORG maximum allowable revenue (green line) is a reasonable
         estimate of efficient total costs;14 then the difference between revenue at the ‘green line’
         level and actual (represented by the Blue line) gives some idea of the cost to consumers
         of the regulatory regime. This difference lies in the range $75-$120M/year. In other
         words, the regulatory regime requires consumers to pay around $100M/year above the
         estimate of efficient cost for DBs to provide network services.

         The form of regulation applied by ORG/ESC was developed because of concern that US-
         style ‘cost-of-service’ regulation tended to produce inefficient outcomes.      The
         ORG/ESC’s regime may be better for consumers than a ‘cost-of-service’ regime, but as
         the above analysis shows, it is clearly not cost free for consumers.

         FIGURE 3: TOTAL REVENUE ($M JUNE 2004) – WITH AND WITHOUT METERING

                                            Total Revenue ($M Jun04 - With and w/o Metering)
$1,550
                Total Revenue DB Forecast
                Total Revenue (Excl Metering) DB Forecast
$1,500          Total Revenue ORG
                Total Revenue Actual
                Linear (Total Revenue ORG)
$1,450
                                                                                                          And this is
                                                                                                          "monopoly
                                                                                                            rent"?
$1,400



$1,350



$1,300

                             This is the true "cost" to
                             consumers of "incentive
$1,250
                               regulation" - around
                           $100M/year. Is it "worth" it?

$1,200
                                                                                       This is a "conservative"
                                                                                           estimate of the
                                                                                         "efficient" revenue
$1,150
                                                                                            "benchmark".


$1,100
         1996     1997     1998      1999     2000         2001   2002   2003   2004      2005     2006      2007       2008   2009       2010




         14
            Ignoring the fact the ORG made it clear the estimate was "conservative and cautious" (i.e. deliberately
         over-stated the efficient revenue level).



                                                                                                                                      8
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




3.1.      The Impact of Strategic Behaviour
It is notable that, even in the first year of the current regulatory period, the DBs benefited
by achieving a revenue outcome nearly $70 million above the efficient benchmark level
set only a month or so before the start of the year. A similar outcome occurred at the
beginning of the first regulatory period. In 1996, actual revenue was around $35 million
above the (supposedly) efficient benchmark revenue set by Government.

In fact, actual revenue exceeded efficient benchmark revenue every year since the DBs
were privatised. Out-performance of revenue projections very early in a regulatory
period suggests that the DB forecasts of sales volumes were conservative. If the DBs
forecast lower sales volumes, they are able to set higher unit prices and capture a benefit
that is unrelated to efficient operation.

The ESC’s Position Paper says:

     “Forecasting is an inherently risky task, even under the most benign circumstances.
     In resetting price caps, however, the task is complicated significantly by the strong
     incentive on the part of the distributors to ‘talk up’ future expenditure, and ‘talk
     down’ future revenue.”15

It is true that sales volume forecasts are uncertain, but robust forecasts would be expected
to be more accurate in the early years of the regulatory period. The possibility that the
DBs are exercising strategic behaviour in their forecasts, as the ESC suggests, must be
addressed.

There is no doubt, in Victoria at least, that the form of regulation implemented by
ORG/ESC ‘works’. As the ESC says, “the approach developed by the ORG for the 2001-
05 determination appears to have been remarkably successful.”16 Overall, the DBs
continually out-perform (supposedly) efficient cost and revenue benchmarks.17

However, the theory of regulation articulated by ORG in its 2000 Decision requires the
efficiency benefits achieved by the DBs to be transferred to consumers after no more than
5 years. If this occurs – and can be verified to consumers’ satisfaction – it would be a
welcome outcome and concrete benefit of incentive regulation. However, the diagrams
and analysis in the ESC’s Papers, and those presented in this submission, show that
efficiency benefits embedded in the DBs’ revenue forecasts for the next regulatory period
are overwhelmed by what looks to be blatant strategic behaviour in forecasting increases
in both operation/maintenance and capital expenditure costs (or excessively high costs of
meeting technical and safety standards). The level of forecast costs are totally
unrecognisable compared to actual cost trends indicated over the last decade.

The ESC clearly recognises this challenge, but does not make it clear in either the Issues
Paper or the Position Paper what it intends to do to ensure consumers get the efficiency

15
    p22, Electricity Distribution Price Review 2006-10 - Position Paper, Essential Services Commission,
March 2005.
16
     Original emphasis. p11, Op Cit.
17
      We note that outcomes in Victoria have been very different to the outcomes achieved in NSW and
Queensland, where all of the electricity distributors have incurred much higher Capex and Opex costs than
they forecast; and performance indicators suggest service standards have fallen.



                                                                                                        9
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




benefits they have, in effect, paid the DBs to achieve. Issues to be considered by the ESC
are:
        How can it be demonstrated that consumers get $75-120 million/year worth of
        benefit from the current regulatory regime?
        Would the situation be different under a different regulatory regime?


3.2.        Issues for the ESC to explain
The data in the diagram above suggests the following issues require further, more detailed
analysis and explanation by the ESC:
        The level of actual revenue is much higher than ORG expected, which needs to be
        explained and taken into consideration in this reset.
        It appears that a primary incentive in the regulatory regime is for DBs to put too
        much effort into sophisticated gaming of demand/cost forecasts.
        The ESC should explain why it is sanctioning a regime where the DBs are paid
        such a high ‘incentive premium’ to do what they should be doing anyway.
        The interval meter roll-out costs seem very high. As discussed later in this
        submission, it is not clear what is driving this.18 It could be:
        −     actual higher costs (because of costs safety/technical regulation suggested by
              the DBs);19
        −     inefficient roll-out configuration (the selective roll-out regime required by the
              ESC will undoubtedly be more costly on a per meter basis than a universal
              roll-out);20 or
        −     strategic behaviour in the cost forecasts by overstating the cost of the roll-out
              knowing that the roll-out will proceed in any case because it has been
              mandated by the ESC.21

Generally, the ESC needs to explain how consumers actually (as opposed to theoretically)
benefit from the incentives in the regime. There is no doubt that the DBs have benefited.
But how do consumers benefit when out-turn Return on Regulated Assets is 50-100%
higher than the efficient benchmark set in 2000?




18
     The ESC has commissioned consultants to review the DBs interval meter roll-out proposals, but has
advised the review will be published with the Draft Determination in June 2005.
19
     The ESC’s Position Paper says: “In the process of replacing meters, it is expected that distributors will
encounter some complex installations arising from unsafe wiring, illegal connections, switchboard
replacements and asbestos meter boards.” (p208)
20
      For example, the ESC’s Position Paper shows each DB has adopted a different roll-out program. Only
United proposes a ‘focussed campaign’ of concentrated roll-out that is likely to generate the economies of
scale similar to those captured by Italian and Ontario distributors.
21
      As noted later in this report, the costs forecast by the DBs are many times higher (on an average per
meter basis) than costs reported for meter roll-outs underway in Italy and Ontario. These latter rollouts
include sophisticated communications and load control capability that is not intended for Victoria at this
stage. That is, both overseas programs will have potential to deliver more flexibility and better options for
consumers, but at very much lower cost, than suggested by the DBs.



                                                                                                            10
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Alternatively, the ESC should explain at what level an efficiency dividend becomes
monopoly rent – when there is an appearance that DBs can capture the efficiency benefit
that is supposed to be passed onto consumers by over-stating their cost forecasts and
understating their sales forecasts. It is of particular concern that it appears a primary
incentive in incentive regulation is created by allowing opportunities for the DBs to earn
above efficient benchmark profits.22

The regulatory regime created by the ORG/ESC allows the DBs to earn additional profits
through five primary mechanisms, and a sixth mechanism is being proposed for the next
regulatory period. These mechanisms are:
        reducing Capex below the forecast amounts;
        reducing Opex below the forecast amounts;
        an efficiency carryover, which allows the DBs to retain the benefits of reducing
        Capex and Opex for a full five-year period;
        an incentive payment to exceed service reliability performance standards;
        retention of part of the forecast amount required to make GSL and appliance
        damage payments; and
        the sixth mechanism proposed by the ESC is in the form of an incentive payment to
        meet the (already excessively costly) interval meter rollout program.

In each case, consumers pay the forecast cost and the DBs benefit in a direct financial
sense by beating the forecasts. What is not clear is whether ‘beating the forecasts’
reflects greater efficiency in terms of a DB becoming more efficient operationally (that is
more productive), or whether the DB has become more effective at playing the regulatory
game and getting consumers to pay for it.

Two primary questions arise from these incentive mechanisms.
        The first is how much does each of these mechanisms actually cost consumers?
        For example:
        −     what is the total value of the efficiency benefit to each DB for Capex and
              Opex;
        −     what is the total value of the efficiency carryover benefit to each DB for
              Capex and Opex;
        −     what is a total value of payment to each distributor in service/quality
              incentives; and
        −     what is the balance in the amounts for GSL's and appliance damage?
        The second question, which is more fundamentally important, is how can
        consumers see they benefit from the efficiency carryover mechanism when the



22
   This submission is not suggesting that the ESC should engage in ‘profit regulation’, but it appears clear that
a much better match is required between forecasts of efficient cost and efficient outcomes. The magnitude of
differences between forecasts and actuals over the last decade strongly indicates that ‘strategic behaviour’ is a
stronger incentive that pursuit of efficiency gains. If this is the case, it is a most unsatisfactory outcome for
consumers because they are being forced to pay unnecessarily high and inefficient costs to receive a more-or-
less basic level of service.



                                                                                                              11
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




          DBs argue they face pressures which will increase costs for the second regulatory
          period?

This comes back to the fundamental question of whether or not the ESC can differentiate
between legitimate prudent behaviour by management in pricing all reasonable risks and
events (that could be legitimately argued should be borne by consumers) and the exercise
of strategic behaviour or gaming by the DBs.

There is no doubt that the key issue for the ESC in this review is to demonstrate to
consumers how they will benefit from the efficiency gains that have so obviously been
achieved by all DBs in the current regulatory period. Ensuring consumers benefit from
efficiency (as required by the Tariff Order and other Victorian legislation) is an essential
tenet of the regulatory regime implemented by ORG/ESC. Delivering these benefits to
end-uses will require the ESC to demonstrate that it can deal with strategic behaviour and
financial engineering by the DBs, both of which are perfectly legal.

Failure by the ESC to clearly explain what the efficiency benefits are, how much they are
worth and to satisfy consumers that they will receive these benefits, would seriously
undermine consumer support for the current form of regulating energy utilities. It
appears from the Issues Paper that the ESC understands it faces this challenge. However,
the Position Paper appears to focus on the ESC’s concern about how best to ensure the
profit incentives in the regulatory framework do not lead to long-term degradation of
asset condition and service level. The Position Paper refers to concerns similar to those
expressed by industry lobbyists such as ‘the criticality of infrastructure investment’ and
the risk to infrastructure investment ‘arising from regulatory processes that may be too
short term in their focus.’ These are real and legitimate concerns for consumers. The
Position Paper seems to recognise that as it refers to the ‘strong incentive on the part of
the distributors to “talk up” future expenditure, and “talk down” future revenue’.

It is clear the DBs are attempting to exercise strategic behaviour by ramping up their
forecast costs way above levels they achieved over the last decade. They did the same
thing in the electricity distribution price review in 2000 and it paid off.

It is absolutely essential for the ESC to demonstrate clearly that it can deliver a fair and
reasonable outcome for both consumers and the DBs from this review.

The analysis presented in this report, which is consistent with information presented in
the ESC’s Position Paper, shows that:

             ORG’s 2000 Decision (and subsequent Appeal) delivered between $75 and $150
             million/year23 in above benchmark revenue benefits to the DBs (that could
             possibly total $500-600 million by the end of the current regulatory period);

             an additional benefit of some $330 million was achieved through the same
             mechanism in the 1996-2000 period; and

             the total efficiency benefits captured by the DBs because their actual costs were
             below the level adopted by Government and ORG for (supposedly) efficient
             revenue building block cost benchmarks are, at least –

23
     All figures in June 2004 dollar values.



                                                                                            12
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




                o    $215 million in the 1996-2000 period for Opex costs alone (noting that
                     Capex efficiency gains were possibly modest because the DBs invested
                     more than forecast in the last 2 years of this period); and

                o    Opex efficiency gains of between $45 million and $60 million/year have
                     been achieved in the first three years of the current regulatory period
                     (ignoring any additional benefit accrued by AGL, Citipower/Powercor
                     and United Energy through the related party arrangements identified by
                     the ESC).

                o    Capex efficiency gains in the current regulatory period are more difficult
                     to estimate, but an indicative figure would appear to be in the range of
                     $10-20 million per year.

That is, cumulative benefits above efficient cost and efficient revenues that have been
captured by the DBs since 1996 appear likely to exceed $1.3 billion (June 2004 dollars)
by the end of the current regulatory period. This is equivalent to about 10% of the total
cost of distribution services paid by consumers.

The ESC’s Position Paper provides a preliminary indication of what this might mean in
terms of tariff price impacts by stating:

        If the Commission was simply to apply the framework and approach without
        any of the proposed step changes in expenditure for changes in functions
        and obligations and growth still under review, this analysis suggests the
        industry-average P0 reduction would be more than 20 per cent..24

That is, if ORG had approved revenue at levels that had matched the actuals, average
distribution prices would have been ‘more than 20 per cent’ lower.

The ORG/ESC efficiency carry-over mechanism implemented in 2001 allows efficiency
benefits achieved in each year of the regulatory period to accrue to the DBs for a period
of five years from the year achieved. Hence, a gain achieved in 2001 would not be
passed on to consumers until 2006 and so on. This mechanism is meant to deliver all
efficiency benefits to consumers after 5 years.25 The ESC must ensure this happens – and
is seen to happen.

ORG determined the efficient benchmark WACC was 6.8% (real, post-tax), yet the DBs
have been consistently achieving out-turn Return on Regulated Assets above that level
since 1996 (see the Table below taken from the ESC's latest Performance Report).




24
    p12, Electricity Distribution Price Review 2006-10 - Position Paper, Essential Service Commission,
March 2005.
25
      The explanation of this mechanism contained in ORG’s 2000 Determination suggests that on a Net
Present Value basis (adjusting for the “time value” of money to allow for the fact that the DBs gain their
benefit before consumers do) the five year period results in a 30/70% split of efficiency gains between DBs
and consumers respectively. This assumes, of course, that the ESC can demonstrate that consumers’ share of
the efficiency gain is not confiscated through DBs overstating cost forecasts for the next regulatory period.



                                                                                                           13
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




TABLE 1: ACTUAL RETURN ON DISTRIBUTION ASSETS (%)

                                       Actual return on distribution assets (%)

DB                             1996          1997      1998       1999        2000       2001   2002   2003

AGL                             10.9       13.1        13.2        12.9           11.5   9.0    7.6      8.2

CitiPower                       13.1       14.3        15.3        14.8           14.5   11.9   11.6    11.9

Powercor                        12.0       13.5        13.9        16.3           16.2   8.7    10.3    11.2

TXU                             13.0       13.6        15.0        15.6           14.4   8.7    9.2     10.6

United Energy                   11.1       10.6        10.3        12.5           13.8   10.9   11.0    11.6




Despite cuts (that the DBs argued were severe) instituted by the ORG in 2000, the DBs’
profitability remained well above efficient levels. When it is considered that the DBs are
geared to significant levels, the actual return on distribution assets shown in the table
below is quite high. A 50% increase in return for an entity geared to 60%, translates – as
a preliminary estimate – into about a 150% increase in Return on Equity (or in the order
of 20-25% real). It should be noted that the DBs do this by not investing in assets.

Consumer representatives who participated in 2000 electricity distribution price review
are fully aware that the 6.8% WACC was acknowledged by ORG to be ‘conservative’
(that is generous to the DBs). It is acknowledged that application of the efficiency
carryover mechanism will result in some increase in returns above the efficient
benchmark WACC. However, the ESC should explain clearly and why consumers
should not consider the substantial outperformance indicated above to be no more than
extraction of monopoly rent.




                                                                                                               14
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




4. Weighted Average Cost of Capital
The value of weighted average cost of capital (WACC) has a significant effect on the
prices paid by consumers. This is because the costs associated with the recovery of
capital, that is return on capital and return of capital (depreciation), comprises around
60% of the DB revenue cash flow.

Unfortunately, and inevitably, the importance of WACC to DBs’ revenue provides strong
incentives for ambit claims and exercise of strategic behaviour (i.e. gaming of the
process, setting of parameters and associated information) by DBs.26 Even more
unfortunately for consumers is the fact that regulators show signs of being susceptible to
the pressure exerted as part of the regulated businesses’ strategic behaviour.27 This
susceptibility is demonstrated through regulators openly acknowledging that their
decisions are ‘cautious’ or ‘conservative’ - meaning they deliberately set WACC values
at the upper end of likely ranges estimated using (what have become in Australia)
“standardised” approaches and analytical techniques.

In the case of Victorian DBs, a 10 basis point increase in WACC delivers around $6
million per year more revenue. The ESC’s approach to determining WACC adds around
90 basis points (“Vanilla”, real, post-tax) compared to judgements made by most other
jurisdictional regulators; at a cost to consumers of around $54 million per year. This is a
clear and very powerful incentive for the DBs to use every possible means to get the ESC
to set higher values than necessary to satisfy the reasonable expectations of financial
markets,28 which should be a key benchmark for regulators.

Although regulators over time have tended to adopt more consistent (and sometimes more
transparent) approaches to setting WACC, which is welcome, there are still
inconsistencies, ambiguities and issues that remain or are poorly explained. The root of
this observation lies in the method employed to estimate the WACC, which can only ever
be approximate and dependent on considerable judgement.

WACC estimates require considerable judgment. For example, the Capital Asset Pricing
Model (CAPM) used to estimate the cost of equity describes the relationship between
expected risk and expected returns. Expectations cannot be measured but require
judgment of those using the model. Further, although the CAPM is a generally accepted
method for measuring the cost of equity it is one of many methods that could be used. No

26
     This behaviour is amply demonstrated by United Energy’s ‘sister company’ Alinta Gas Networks
(AGN). AGN recently lodged a proposal with the Economic Regulatory Authority in WA that argues ERA
should follow the lead of Ofgem (and ESCoSA) and change the method for determining the Risk Free Rate
because Government Bonds are currently at historically low levels.
There is a rational argument that using a 20 day average of Government bonds is not the best way to estimate
a Risk Free Rate that is intended to be used to estimate a projected cost of debt over a five year period. But
AGN's opportunism is narrow, selective, obvious and self interested. There is no mention in the AGN
proposal that Ofgem also adopts a substantially lower Equity Risk Premium (MRP in Australia). Nor does
AGN mention that it accrued substantial benefits over the previous five years because Government Bond
rates fell by 150 Basis Points (presumably allowing AGN to benefit through lower borrowing costs).
27
     There is also recent evidence from the UK that similar outcomes are occurring there.
28
      The EUAA and EAG have experience with some 20 or so regulatory reviews, involving transmission
and distribution in both electricity and gas. They have observed such tactics being used on a consistent basis
with regulators all succumbing to some extent and resulting in higher prices for customers.



                                                                                                            15
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




theoretical correct model exists to measure the cost of equity or indeed the WACC. With
a considerable level of judgement involved in any WACC estimate it is extremely
important that regulators balance the interests of utilities and consumers in setting
WACC.

It is also clear that consumer input into regulatory reviews has been and remains
inadequately resourced, especially compared to that of the DBs. This creates an
asymmetry in the information and argument provided to regulators. Although regulators
are aware of this imbalance, they nevertheless persist in setting inflated WACCs. It is
clear that regulators are not well equipped to put themselves into the shoes of consumers.
The perception raised by some that regulators do sympathise with consumers detracts
from the credibility of the regulatory regime and gives regulated businesses more head
room to challenge the regulators (with some beneficial outcomes for the businesses, it
appears).

Our comment on WACC issues is structured as follows:
        first, we present a brief summary of the DBs’ proposals;

        second, we discuss a number of fundamental issues related to the estimation of
        WACC for regulated utilities that is intended to assist the ESC and other Australian
        regulators in their determination of the WACC;

        third, we provide a benchmark comparison between UK and Australian regulators
        for different WACC decisions;

        forth, we provide some (technical) commentary on individual selected parameters
        referred to in the ESC’s Issues Paper;

        fifth, we discuss the choice of Capital Asset Pricing Model (CAPM) model as the
        tool preferred by Australian regulators to estimate WACC components; and

        finally, we provide a conclusion and estimate the cost to consumers of the ESC’s
        retention of a WACC value and input parameters proposed by the DBs, which we
        note are similar to those ORG adopted in the December 2000 Decision.


4.1. What the DBs want

The DBs’ proposals for WACC are summarised by the ESC in Table 5.1 of the Issues
Paper.29 The DBs propose a minimum “Vanilla”, real, post-tax WACC30 of 6.7-6.8%
(excluding a ‘rural risk adjustment’ proposed by Powercor).

WACC at the level proposed by the DBs is at the upper range of values endorsed by
Australian regulators since 1998; and substantially above IPART's recent values of 5.0%


29
     p86-87, ESC Issues Paper.
30
     We note that terms and approaches used by different regulators for WACC are incomprehensibly
confusing to consumers (and in some cases, it appears, even to the regulators themselves). We do not address
each of the different approaches in this report. Suffice it to say that we fully endorse ORG’s decision in 2000
to adopt what it calls the “Vanilla”, real, post-tax WACC. This is the simplest approach used by regulators to
estimate WACC and it allows the cost of tax to be treated separately and transparently in the revenue
determination.



                                                                                                            16
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




for water businesses and 6.0% for electricity distributors and a value of 5.1% recently
proposed by the ESC for Victorian water businesses.

KPMG provided advice on WACC to the AGL, TXU (SPI) and United Energy. In
summary, KPMG’s advice is that:
        market risk premium (MRP), which is a key and still very contentious parameter
        used to estimate WACC, should be higher than 6.0% (8.0% seems favoured),
        although the DBs appear to have adopted 6.0% on the basis that this is almost
        universally preferred value of Australian regulators;
        equity beta, which is another key and equally contentious parameter used to
        estimate WACC, should be more than 1.0; and
        debt margin should be about the same as that adopted by ORG in 2000 (even
        though IPART recently adopted a BBB+ Commercial Debt instrument as a (lower)
        “benchmark” for efficient cost of debt for NSW DBs, and the ESC has indicated it
        may follow this “innovation” for the Victorian water utilities).

There is very little reference to, or analysis of, outcomes in the UK in the KPMG advice,
or any clear recognition that all regulators (even those in Australia) consistently make the
point that their judgements are ‘cautious’ and deliberately favour utilities (so as not to act
as a disincentive to investment). Nor is there any comment on the outcomes from ORG’s
2000 Determination, which delivered Return on Regulated Assets 50-100% higher than
(what ORG argued at the time was) an efficient but ‘conservative’ estimate for the cost of
capital.

The KPMG advice contains a summary of research reports dealing with the vagaries and
challenges of estimating MRP and equity beta, but appears to make a one-sided
presentation of the arguments. For example:
        In reference to MRP and international evidence, KPMG says that, "In addition, we
        consider that the ESC should rely on Australian data on the MRP rather than data
        on other markets (e.g. the USA) given the structural and other differences between
        equity markets." But they present no direct evidence that identifies these
        "structural and other differences".31
        There is no comment at all on the UK experience with MRP values that place
        greater weight on market evidence than analysis of long-term historic data.
        KPMG refer to previous regulatory decisions in Australia if there is no other reason
        to justify a number that is higher than any reasonable interpretation of the evidence
        they quote.

Citipower/Powercor have taken a different line. Citipower/Powercor‘s principle
argument is that regulators fail to satisfactorily deal with statistical variation of CAPM
parameter data. This is literally correct − but hardly unbiased − given that regulators
always come down on the side of ‘conservative’ judgements. It is correct that the
regulators do not use statistical techniques to account for the impact of data variability.
However, the regulators’ judgements inevitably take account of doubt, variation and
uncertainty in the data by selecting values that are higher than a simple average of all
information available to them. Nor do Australian regulators place any weight on

31
     We refer to our discussion in section 4.4.1 on recent analysis of factors affecting the MRP.



                                                                                                    17
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




information such as surveys of investor expectations that are given weight by UK
regulators.

Again no mention is made of the UK experience, other than a quote from the ESC's 2002
Gas Distribution decision to the effect that we now have local data and do not need to
look at UK precedents.32 Given the continuing relative paucity of market data in
Australia, consumers see clear reason to argue against the ESC accepting this line of
argument.

Powercor/Citipower suggest a purely statistical approach (based on analysis of long-run
historical data) and recommend setting all the parameter values at a figure established by
(what appears to be) a ‘confidence interval’ of 70%. That means, more-or-less, that the
ESC should be ‘confident’ that adopted values of CAPM parameters are higher than at
least 70% of observed data.

The Powercor/Citipower submissions reproduce a diagram taken from a recent QCA
Determination (see below), which shows the variation in MRP on an annual and 10 yearly
moving average basis. This shows there has been significant volatility in MRP, which
appears to have increased in the post-war years (for the annual average values), and since
the late 1960s for the 10-year moving average - with extended periods when the 10-year
moving average has been well below the longer term value commonly quoted by the DBs
(of 6-8%). For example:
        During the early 1970s, the 10-year average MRP dropped below zero; and
        Since the late 1980s, the 10-year average has tended to stay below the 6-8%
        range.33

It is not entirely clear what this should mean to the ESC. However, it is clear that
consistently adopting a Confidence Interval of 70% each regulatory period would, in the
long term, ensure that consumers were paying well-above efficient levels of any
reasonable value of the cost of capital.




32
      Ignoring overseas data and relying solely on local precedents will result in a circular problem in the
setting of WACC. In effect, the inflated values used are far more likely to become “institutionalised” and
perpetuated.
33
     A range of 6-8% based on historic data is consistent with analysis quoted by UK regulators – even
though they adopt substantially lower value in their decisions.



                                                                                                          18
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




FIGURE 4: ANNUAL AND 10 YEAR MOVING AVERAGE MRP IN AUSTRALIA




(Source: QCA, Proposed Access Arrangements for Gas Distribution Networks, October 2001, page 216)



It is also notable that major changes have occurred since the early 1970s that have
impacted directly on Australian and international financial markets. In respect of
KPMG’s “structural and other differences” line of argument, the ESC would be aware
that there are also very substantial similarities between Australian financial markets and
related markets elsewhere. Not least of these is the impact on financial markets flowing
from the tumultuous changes in oil prices (see below), which contributed to the Whitlam-
era inflationary spike in Australia.

The relatively strong performance of the Australian economy over the last decade has, no
doubt, been aided by fundamental changes to Australian financial market arrangements
exemplified by floating of the Australian dollar in December 1983 and opening
Australia’s financial markets to participation by foreign banks in September 1987.




                                                                                                    19
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




FIGURE 5: CRUDE OIL PRICES (US$2000/BARREL)




                                                 20
       Victorian Consumers’ Groups
       VIC 2006 Electricity Distribution Price Review




       FIGURE 6: AUSTRALIAN INFLATION


                                      Weighted average eight capital cities


25%


20%


15%


10%


  5%


  0%
       0


                  5


                             0


                                        5


                                                   0


                                                              5


                                                                         0


                                                                                    5


                                                                                               0


                                                                                                          5


                                                                                                                     0


                                                                                                                                5
    /5


               /5


                          /6


                                     /6


                                                /7


                                                           /7


                                                                      /8


                                                                                 /8


                                                                                            /9


                                                                                                       /9


                                                                                                                  /0


                                                                                                                             /0
 49


            54


                       59


                                  64


                                             69


                                                        74


                                                                   79


                                                                              84


                                                                                         89


                                                                                                    94


                                                                                                               99


                                                                                                                          04
19


           19


                      19


                                 19


                                            19


                                                       19


                                                                  19


                                                                             19


                                                                                        19


                                                                                                   19


                                                                                                              19


                                                                                                                         20
       The impact of these major changes in Australian financial markets strongly suggests it is
       inappropriate for regulators to assume that long-run historical data should be used as the
       basis for estimating values for either MRP or equity beta. Consideration of these factors
       argues in favour of placing greater weight on the view of financial market participants
       about their expectations than on analysis of long-run historical data.

       If regulators were to use statistical analysis they would need to ensure that all (expected)
       inputs to the WACC formula were unbiased and did not contain any element of
       ‘conservatism’. Further, depending on the statistical approach adopted, the regulator
       would likely need to expand on the number of assumptions (such as probability
       distributions and variances) already adopted in a CAPM framework. Accordingly, any
       statistical analysis would be inappropriate in the current context and only serve to
       decrease transparency in a process that already provides little confidence for consumers.


       4.2. WACC and effective regulation

       The main issues related to regulatory judgement on WACC remains the value of two key
       parameters required for application of the Capital Asset Pricing Model (CAPM) - the
       MRP and the equity beta. The value of both, and the way this value is established, is still
       subject to considerable debate. An essential platform in this debate has been noted by the
       Productivity Commission. In the report on the National Access Regime, the Productivity
       Commission argues that regulators should always err on the side of setting a higher


                                                                                                                          21
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




WACC because this provides a clear incentive for asset owners to continue investment in
network infrastructure.34

While it is accepted that clear and consistent incentives are required to ensure ongoing
investment, sufficient evidence exists to seriously question the Productivity
Commission’s conclusions. It is a fundamental requirement for regulators to undertake
careful analysis and make considered, well-informed and independent decisions focussed
on outcomes that emphasise broad economic benefits. Regualtors should steer away from
making decisions that focus primarily on protecting the long-term interests of existing
utility shareholders. This is particularly important in the context of setting a WACC for a
regulated business, where there is considerable room for judgement in the final choice of
value.

It is imperative that regulators form robust views on these matters and minimise bias in
their judgements. This is becoming more-and-more possible with the now substantial
track record of regulatory decisions in Australia (and elsewhere). Indeed virtually all
regulators’ decisions systematically discuss decisions by other Australian regulators, and
use this discussion as a substantial basis for numerous aspects of their own decisions. It
would seem that regulators have a capacity to follow an approach that makes it possible
to refine the setting of WACC parameters and reduce the need for regulatory judgement
(as well as regulatory risk). However, as discussed in the following sections, it is of
concern that this is not the case.

Regulators should focus on the genuine long-term interests of consumers and adequately
challenge monopoly service providers. ‘Favouring’ monopolists is poor regulatory
practice. The monopolists will always pay themselves too much; much more so than
most efficient competitive market service providers.

A fundamental purpose of effective regulation of monopolies is to deliver outcomes
similar to those that would be delivered if effective competition were possible. It is
axiomatic that, if competition is effective, successful firms manage to do three things:
        reduce all their costs, including financing and taxation costs, to a minimum
        sustainable level;
        provide services that consumers value; and
        allow consumers to capture benefits through prices that are related to the efficient
        cost of production (or supply) – at the same time as the quality of the goods and
        services provided is improved by ongoing investment in capacity.

If they can do these things, firms in competitive markets will be profitable, they will have
satisfied customers and financial markets will voluntarily support them.




34
   For example, see Box 13.1, p354, Review of the National Access Regime – Inquiry Report, Productivity
Commission Report No 17, 28 September, 2001.
As this report shows, Australian regulators are already setting WACC at levels substantially higher than UK
regulators. The ORG/ESC stands out as a regulator setting amongst the highest WACCs in Australia. It is
unclear how the Productivity Commission’s position should be interpreted. The Productivity Commission
report contains very little analysis of comparative WACCs and bases its conclusions and recommendations
more on rhetoric than fact.



                                                                                                         22
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




The ESC has demonstrated its awareness that it has a key role and responsibility to
ensure, as far as practicable, that similar outcomes are achieved through regulation of the
electricity distribution sector in Victoria.


4.3. Benchmarking

The material below shows a ‘benchmarking’ comparison of return on equity, cost of debt
and WACC.35 The approach taken is to use values of CAPM parameters selected by
individual regulators to derive estimates of real cost of debt, return on equity and the
‘Vanilla’ WACC.36 This allows a (nearer) ‘apples-for-apples’ comparison of the
outcomes from regulatory decisions than is possible by using numbers derived from
different versions of CAPM, or by using nominal values that do not exclude the impact of
inflation.

The ‘Vanilla’, real post-tax WACC has been chosen to ‘normalise’ this comparison
because this has the simplest and most easily understood formula. The relative simplicity
minimises confusion and provides a means for improving transparency surrounding most
decisions on the WACC. Further, as mentioned above, this formula eliminates time
dependant changes in inflation and avoids the need to allow for tax costs within the
CAPM.

One of the principal advantages of using the ‘Vanilla’ WACC formula, which was clearly
articulated by ORG in its 2000 Final Decision, is that regulators are then able to deal with
the cost of tax transparently and directly by adding an additional line item for estimated
tax costs to the Revenue Building Block.

It is acknowledged that these are ‘noisy’ diagrams that are difficult to interpret. That is,
in a sense, one of their strengths.

The outcomes from regulators’ deliberations on WACC values and the parameters used to
estimate WACC are intended to reflect the costs of capital for efficient, well-managed
firms – from the perspective of efficient financial markets.37 It is clear that is the view
that UK regulators take; and that view is consistent with the stated intent of the ORG/ESC
is establishing ‘efficient’ costs for other components of the regulatory Revenue Building
Blocks. If the WACC values do, in fact, reflect the cost of capital to efficient, well-

35
     Data in this form was first presented to the ACCC in 2002 on behalf of BHP-Billiton by Pareto
Associates Pty Ltd. The data provided in this report has been updated by MJA to reflect the latest available
information from regulatory decisions in the UK and Australia.
An earlier version of this information was presented to the ESC’s gas distribution price review in 2002, but
arguments supporting the conclusions drawn from this ‘benchmarking’ analysis have been refined since 2002.
Accordingly, the ESC is urged to consider it carefully in this review.
36
      It should be noted that regulators almost universally adopt parameter values for estimating WACC, or
final WACC values, that are above mid-range estimates quoted in their determinations. The basis of
judgement for selecting a particular WACC value is sometimes not clearly explained in regulators’
determinations, making it impossible to back-calculate a value for individual parameters that would yield the
final WACC value. Therefore, the values shown on the diagrams below are likely to be somewhat lower than
the regulator might have selected if the “Vanilla”, real, post-tax formula had been applied using a single value
for each CAPM/WACC parameter.
Where regulators quote a range of parameter values, a mid-point estimate of the “Vanilla”, real, post-tax
WACC has been estimated and shown on the diagrams in this paper (and in Appendix B).
37
     Alternatively, the WACC might represent the cost of capital to efficient utility industry sectors.



                                                                                                             23
        Victorian Consumers’ Groups
        VIC 2006 Electricity Distribution Price Review




        managed, businesses, it would be expected that regulators would develop a consistent
        view of what constitutes the cost of capital. But that is not what these diagrams indicate
        for Australian regulators. As noted in more detail below, Australian regulators make
        more noticeably varied judgements on WACC for individual businesses in the same
        utility sectors and between utility sectors that their UK counterparts. It is this variability
        in outcome of regulators’ decisions that creates the ‘noise’ (and difficult interpretation)
        that is so obvious.


        4.3.1. Comparison of cost of equity

        Figure 7 below shows values for the (real, post-tax) return on equity (cost of equity)
        estimated by reference to the judgements by Australian and UK regulators on values for
        the CAPM parameters for the range of decisions since 1994.38

        FIGURE 7: ESTIMATED RETURN ON EQUITY (REAL, POST-TAX)

                                                                                                                                          IPART 1999 ED (Mid)

12.0%                                                                                                                                     SA EPO 1999 ED (Mid)


        ESTIMATED RETURN ON EQUITY (Real, post-tax)
                                                                                                                                          ACCC 2000 ETN (Mid)
                                                                                                                                          ORG 2000 ED
                                                                                                                                          QCA 2000 ED
                                                                                                                                          ACCC 2001 ETQ

11.0%                                                                                                                                     ACCC 2002 ETS
                                                                                                                                          ACCC 2002 ETV
                                                                 ORG 1998 GD
                                                                                                                                          OTER 2003 ED
                                                                                                                                          ACCC 2003 ETT
                                                                                                                                          ICRC 2004 ED

10.0%                                                                                                                                     ACCC 2004 ETN
             ◊ Electricity (Red=AUS; Blue=UK)                                                                                             IPART 2004 ED (Mid)
                                                                                                  ESC 2002 GD
             o Gas (Orange=AUS; Blue=UK)                                                                                                  ESCoSA 2005 ED
                                                                          ORG 2000 ED
             ∆ Water (Lt Blue=AUS; Blue=UK)                                                                                               QCA 2005 ED
             □ Other (Red=AUS; Blue=UK)                                                                                                   ERA 2005 ED

9.0%                                                                                                                                      IPART 1997 GD (Mid)
                                                                                                                                          ACCC 1998 GTV
                                                                                                                                          ORG 1998 GD
                                                                                                                                          OFFGAR 2000 GD
                                                                                                                                          IPART 2000 GD (Mid)

8.0%                o ORG 1998 GD, 10.40%
                                                                                                                                          QCA 2001 GD
                                                                                                                                          ESC 2002 GD
                    ◊ ORG 2000 ED, 9.50%                                                                                                  ACCC 2002 GTV
                    o ESC 2002 GD, 9.40%                                                                                                  OFFGAR 2003 GT
                    ◊ ESC 2004 ED (IP Interp), 8.65%                                                                                      ICRC 2004 GD (Mid)
7.0%                                                                                                                                      IPART 2004 GD (Mid)
                                                                                                                                          IPART 2000 W&S (Mid)
                                                                                                                          ESC 2005 W&S    GPOC 2001 BW (Mid)
                                                                                                                                          QCA 2003 RW
                                                                                                                                          IPART 2003 W&S (Mid)
6.0%                                                                                                                                      ICRC 2004 W&S (Mid)
                                                                                                                                          GPOC 2004 W (Mid)
                                                                                                                                          ESC 2005 W&S
                                                                                                                                          IPART 1999 Rail (Mid)
                                                                                                                                          QCA 2004 Ports
5.0%                                                                                                                                      OFFER 1994 ED (Mid)
                                                                                                                                          UKCC 1994 ED
                                                                                                                                          OFGEM 1999 ED
                                                                                                                                          OFGEM 2000 ET
                                                                                                                                          OFGEM 2004 ED
4.0%                                                                                                                                      OFGEM 2001 GT&D
                                                                                                                                          OFWAT 1994 W&S
         91        92        93        94       95     96   97       98        99       00   01      02         03   04       05          OFWAT 1999 W&S (Mid)
                                                                                                                                          OFWAT 2004 W&S (Mid)




        From 1994 to 2002 the values adopted by UK regulators can be seen to lie in a relatively
        narrow range of 5.2% to 6.2% (real, post-tax). More recently, however, the cost of equity
        allowed by UK regulators has increased significantly. The logic supporting this increase
        is most clearly articulated for the water sector, where the UK water regulator OFWAT



        38
             The diagrams below all have the following common characteristics: ◊ = Electricity (Red=AUS;
        Blue=UK); o = Gas (Orange=AUS; Blue=UK); ∆ = Water (Lt Blue=AUS; Blue=UK); □ = Other
        (Red=AUS; Blue=UK)



                                                                                                                                     24
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




has stated that it has adopted a significant change in emphasis in key judgements related
to the WACC. The most marked changes are:
        formal acknowledgement of a move away from reliance on the use of CAPM as the
        primary tool for estimating return on equity;
        greater reliance on information from, and views of, financial market analysts and
        observers about the expectations of debt and equity providers;
        acceptance of a view that financial market expectations have changed in that equity
        providers expect higher returns than in the recent past;
        a move away from adopting risk free rate parameter values based on direct
        observation of Gilt Bond rates, which are at historically low levels, that may be
        unsustainable over the next regulatory period; and
        reaffirmation that it is appropriate to extend ‘size-premiums’ to allow for higher
        cost of financing for the (relatively) smaller water-only companies.39

A manifestation of this changed view is acceptance of slightly higher values for the key
WACC parameters for the risk free rate, market risk premium, equity beta and a wider
range of ‘size-premiums’ for water-only companies than adopted in the 1999
Determinations. Nevertheless, similarity of view between different UK regulators on the
cost of equity for utilities has been maintained – that extends to the rail, airports and
communications sectors.

The similarity of view across industries and sectors observed in UK regulators’ decisions
is not a feature of Australian regulators’ judgements on the value for parameters required
to estimate the return on equity. In particular, the view taken by Australian regulators
about the return on equity that is appropriate for energy and water utilities is markedly
dissimilar to their UK counterparts.40 As can be seen, there is far greater difference
between Australian regulators’ judgements on the cost of equity for different industries –
even for the same sectors of the same industries – than is the case in the UK. For
example:
        the CAPM parameter values adopted by QCA in 2004 and 2005 yield return on
        equity estimates from 6.59% for the water sector to 8.03% for electricity
        distributors;
        a noticeably more divergent difference is indicated in the ORG/ESC’s decisions,
        with return on equity of 9.5% for electricity distributors in 2000, 9.4% for gas
        distributors in 2002, but only 7.0% for water utilities in its recent Draft
        Determination; and


39
      The ESC should note that the highest ‘size premiums’ apply to very small firms with regulated asset
values of less than AU$170 million (£70m) – and no ‘size premium’ applies to firms with regulatory asset
values of more than AU$1.7 billion (£700m). On that basis, arguments supporting application of a ‘size
premium’ for small UK water-only companies is not translatable to regulation of energy utilities in Australia
(or the UK for that matter).
40
      A possibly rational conclusion is that this divergence is directly related to the effectiveness of assertive
‘strategic behaviour’ exhibited by water sector protagonists in the UK and energy sector protagonists in
Australia - both having conducted prolonged campaigns to ‘convince’ governments and regulators that
greater ‘investment incentives’ are needed to ensure ongoing support by equity providers. This could be
described as a form of well-orchestrated and ‘institutionalised’ monopoly behaviour.




                                                                                                               25
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        ESC’s CAPM parameter values give an estimate for return on equity of 9.40%
        (2002) for gas distribution in Victoria, and ICRC’s 8.59% (2004) for ACT; while
        IPART’s values give 8.01% (2004) for NSW gas distribution.

We suggest the ESC address this issue by answering the following question:

Why should Victorian electricity consumers pay for a higher cost of capital than
consumers in other jurisdictions, or pay for a higher cost of capital for electricity
distribution than water consumers?

The ESC’s commentary in its Paper sheds little light at all on this question, an answer to
which is likely to improve the regulatory process and lead to more consistent decisions
moving forward.


4.3.2. Comparison of the cost of debt

Figure 8 below shows values for the (real, pre-tax) cost of debt estimated by reference to
the judgements by Australian and UK regulators for a range of decisions. The figure
shows that real (pre-tax) values for the cost of debt generally lie within a band between
3.8 – 4.8% for both UK and Australian utilities, across sectors. It is notable that estimates
accepted by ORG/ESC and QCA in 2000 (and more recently ESCoSA) are higher than
those accepted by other Australian regulators. It is also notable that both ERA and QCA
have recently accepted cost of debt values that reflect historically low Government Bond
rates. By contrast, ESCoSA responded to pressure from ETSA utilities in 2004 and
adopted a fundamentally different approach to that used by other Australian regulators for
establishing the risk free, which yielded a substantially higher estimate for the cost of
debt.41

This data shows that UK regulators generally adopt slightly lower values for the cost of
debt than Australian regulators for the same industry sector which is related (primarily) to
differences in the price of Government Bonds that have a substantial influence on
selection of a risk free rate. However, there is generally greater difference between
Australian regulators. This is partly because:
        of significant fluctuations in Australia’s Commonwealth Treasury Bond rates (that
        are not ‘ironed out’ by adopting a more volatile 20 day moving average as the
        ‘proxy’ for what is effectively a 5-year forecast);42 and
        Australian regulators adopt different approaches for estimating debt margins and
        some have ‘tinkered’ with debt margins that they acknowledge are already
        ‘cautious’ and ‘conservative’ (i.e. favour regulated utilities) by adding incremental
        amounts for ‘debt financing cost’ and ‘cost of debt hedge timing’.



41
      Most Australian regulators, including the ESC, use the average of the Government Bond rate in the 20
days preceding their Determinations to establish the risk free rate. ESCoSA adopted a 5 year average in
response to ETSA Utilities assertion that Government Bonds were at historical low levels that were unlikely
to be maintained during the coming regulatory period.
While ETSA Utilities assertion is correct, it is beyond doubt that ETSA Utilities argued this case because it
would be better off than if ESCoSA followed precedents set by other Australian regulators.
42
     This matter is discussed in further detail later in this submission.



                                                                                                           26
       Victorian Consumers’ Groups
       VIC 2006 Electricity Distribution Price Review




       FIGURE 8: ESTIMATED COST OF DEBT, REAL PRE-TAX

                                                                                                                                            IPART 1999 ED (Mid)

7.0%                                                                                                                                        SA EPO 1999 ED (Mid)
                                                                                                                                            ACCC 2000 ETN (Mid)
       ESTIMATED COST OF DEBT (Real, pre-tax)                                                                                               ORG 2000 ED
                                                                                                                                            QCA 2000 ED
                                                                                                                                            ACCC 2001 ETQ

6.5%                                                                                                                                        ACCC 2002 ETS
                                                                                                                                            ACCC 2002 ETV
                                                                                                                                            OTER 2003 ED
                                                                                                                                            ACCC 2003 ETT
                                                                                                                                            ICRC 2004 ED

6.0%                                                                                                                                        ACCC 2004 ETN
        ◊ Electricity (Red=AUS; Blue=UK)                                             o ORG 1998 GD, 4.59%                                   IPART 2004 ED (Mid)
        o Gas (Orange=AUS; Blue=UK)                                                  ◊ ORG 2000 ED, 5.00%                                   ESCoSA 2005 ED
        ∆ Water (Lt Blue=AUS; Blue=UK)                                               o ESC 2002 GD, 5.09%                                   QCA 2005 ED

        □ Other (Red=AUS; Blue=UK)                                                   ◊ ESC 2004 ED (IP Interp), 4.39%                       ERA 2005 ED

5.5%                                                                                                                                        IPART 1997 GD (Mid)
                                                                                                                                            ACCC 1998 GTV
                                                                                                                                            ORG 1998 GD
                                                                                                                                            OFFGAR 2000 GD
                                                                             ORG 2000 ED
                                                                                                       ESC 2002 GD                          IPART 2000 GD (Mid)

5.0%                                                                                                                                        QCA 2001 GD
                                                                                                                                            ESC 2002 GD
                                                                                                                                            ACCC 2002 GTV
                                                                                                                                            OFFGAR 2003 GT

                                                     ORG 1998 GD                                                                            ICRC 2004 GD (Mid)

4.5%                                                                                                                                        IPART 2004 GD (Mid)
                                                                                                                                            IPART 2000 W&S (Mid)
                                                                                                                                            GPOC 2001 BW (Mid)
                                                                                                                                            QCA 2003 RW
                                                                                                                                            IPART 2003 W&S (Mid)
4.0%                                                                                                                                        ICRC 2004 W&S (Mid)
                                                                                                                                            GPOC 2004 W (Mid)
                                                                                                                                            ESC 2005 W&S
                                                                                                                                            IPART 1999 Rail (Mid)
                                                                                                                                            QCA 2004 Ports
                                                                                                                             ESC 2005 W&S
3.5%                                                                                                                                        OFFER 1994 ED (Mid)
                                                                                                                                            UKCC 1994 ED
                                                                                                                                            OFGEM 1999 ED
                                                                                                                                            OFGEM 2000 ET
                                                                                                                                            OFGEM 2004 ED
3.0%                                                                                                                                        OFGEM 2001 GT&D
                                                                                                                                            OFWAT 1994 W&S
       91       92        93        94     95   96       97        98   99      00         01     02        03          04       05         OFWAT 1999 W&S (Mid)
                                                                                                                                            OFWAT 2004 W&S (Mid)




       It appears clear that Australian regulators should adopt a more consistent and pragmatic
       approach in estimating the cost of debt. Clearly it is inconsistent to calculate an
       ‘accurate’ value for the risk free rate (by using a 20-day average that is demonstrably
       volatile), then adopt a basic debt margin and various ‘add-ons’ that are ‘cautious’ and/or
       ‘conservative’ – and not directly related to efficient, observable cost of debt for regulated
       entities. Nor should regulators assign a cost of debt that suits an individual regulated
       entity, or precisely matches the actual cost of debt incurred by the regulated entity,
       because this would be inconsistent with a principle of ‘incentive’ regulation.

       Ideally, regulators − including the ESC − should adopt a ‘benchmark’ cost of debt that is
       ‘efficient’ but still provides an incentive for ‘efficient, well-managed’ utilities to lower
       their financing cost. The ‘benchmark’ should provide a challenge that forces less-
       efficient and less well-managed utilities (i.e. those with financing cost above the
       ‘benchmark’) to ‘lift their game. It is axiomatic that regulators should also then develop a
       longer-term mechanism to transfer the financing ‘efficiency gain’ to consumers through
       progressively lowering cost of debt so that it matches a truly ‘efficient benchmark’.


       4.3.3. Comparison of Vanilla WACCs

       The figure below compares regulatory decisions using the real, post-tax ‘Vanilla’ WACC.
       The figure clearly shows that Australian regulators have made judgements that result in


                                                                                                                                       27
       Victorian Consumers’ Groups
       VIC 2006 Electricity Distribution Price Review




       WACC values that are far more varied than those made by UK regulators administering
       similar incentive regulation regimes.

       With regard to the ESC it is noted that:
                 it continues to adopt the highest value WACC in Australia for electricity (and gas)
                 distribution, with values ranging from 60-120 basis points higher than other
                 jurisdictional regulators (an average of 90 basis points); and
                 it has recently indicated it proposes a lower value of WACC of 5.1% for the water
                 sector.



       FIGURE 9: ESTIMATED "VANILLA", POST-TAX WACC

                                                                                                                                            IPART 1999 ED (Mid)

9.0%                                                                                                                                        SA EPO 1999 ED (Mid)


       ESTIMATED WACC ("Vanilla" Real, post-tax)
                                                                                                                                            ACCC 2000 ETN (Mid)
                                                                                                                                            ORG 2000 ED
                                                                                                                                            QCA 2000 ED

8.5%                                                                                                                                        ACCC 2001 ETQ
                                                                                                                                            ACCC 2002 ETS
                                                                                                                                            ACCC 2002 ETV
                                                                                                                                            OTER 2003 ED

8.0%                                                                                                                                        ACCC 2003 ETT
                                                                                                                                            ICRC 2004 ED
                                                                                                                                            ACCC 2004 ETN
       ◊ Electricity (Red=AUS; Blue=UK)                                                                                                     IPART 2004 ED (Mid)

7.5%   o Gas (Orange=AUS; Blue=UK)                                                                                                          ESCoSA 2005 ED
       ∆ Water (Lt Blue=AUS; Blue=UK)                                                                                                       QCA 2005 ED
       □ Other (Red=AUS; Blue=UK)                                                                                                           ERA 2005 ED
                                                                                                                                            IPART 1997 GD (Mid)

7.0%                                                     ORG 1998 GD
                                                                                 ORG 2000 ED                                                ACCC 1998 GTV
                                                                                                                                            ORG 1998 GD
                                                                                                         ESC 2002 GD                        OFFGAR 2000 GD
                                                                                                                                            IPART 2000 GD (Mid)
            o ORG 1998 GD, 6.93%
6.5%        ◊ ORG 2000 ED, 6.80%
                                                                                                                                            QCA 2001 GD
                                                                                                                                            ESC 2002 GD
            o ESC 2002 GD, 6.80%
                                                                                                                                            ACCC 2002 GTV
            ◊ ESC 2004 ED (IP Interp), 6.09%                                                                                                OFFGAR 2003 GT

6.0%                                                                                                                                        ICRC 2004 GD (Mid)
                                                                                                                                            IPART 2004 GD (Mid)
                                                                                                                                            IPART 2000 W&S (Mid)
                                                                                                                                            GPOC 2001 BW (Mid)
5.5%                                                                                                                                        QCA 2003 RW
                                                                                                                                            IPART 2003 W&S (Mid)
                                                                                                                                            ICRC 2004 W&S (Mid)
                                                                                                                                            GPOC 2004 W (Mid)
5.0%                                                                                                                                        ESC 2005 W&S
                                                                                                                            ESC 2005 W&S    IPART 1999 Rail (Mid)
                                                                                                                                            QCA 2004 Ports
                                                                                                                                            OFFER 1994 ED (Mid)
4.5%                                                                                                                                        UKCC 1994 ED
                                                                                                                                            OFGEM 1999 ED
                                                                                                                                            OFGEM 2000 ET
                                                                                                                                            OFGEM 2004 ED
4.0%                                                                                                                                        OFGEM 2001 GT&D
                                                                                                                                            OFWAT 1994 W&S
       91        92        93        94        95   96       97        98   99      00         01   02      03         04       05          OFWAT 1999 W&S (Mid)
                                                                                                                                            OFWAT 2004 W&S (Mid)




       Interestingly, it would seem there is a downward trend in the WACC decisions taken by
       Australian regulators over the last few years. However, only one observation is available
       for 2005. It is therefore possible that Australian regulators are responding to legitimate
       consumer concerns and gradually lowering WACC to bring it closer to values assigned by
       UK regulators.




                                                                                                                                       28
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




The analysis also shows Australian regulators have generally endorsed outcomes that,
unfortunately for consumers, ensure Australia's energy networks will be less ‘efficient’
(i.e. more costly to consumers) than in the UK. This is not a desirable outcome for
customers, especially those operating in competitive world markets.




                                                                                      29
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




It is therefore suggested that the ESC answer the following question:

What are the differences between the UK and Australia that justify the assumption that
investors’ expectations differ? OR: Why is a Market Risk Premium of no more than 5%
accepted by UK utility investors, when Australian regulators judge Australian utility
investors expect 6%?



While some of the difference may be explained by differences in approach, as discussed
in section 4.4.1 below, the is no clear evidence that international financial markets see
Australian utilities as less efficient and more costly to finance than their UK (and US)
counterparts. For reasons that have never been adequately and transparently explained,
regulators persist with decisions that suggest the opposite. That is, regulators are out of
tune with financial markets.


4.4. Individual Parameters

Australian regulators and regulated businesses put substantial effort into arguing for
particular values of individual parameters in the CAPM and WACC formulae. However,
it is clear that the value adopted by regulators for individual CAPM parameters is not as
important as the final value of WACC that the parameter values yield. Ultimately, the
value of any individual parameter, be it the market risk premium (MRP) or equity beta, is
only meaningful if the final value of WACC produced by the CAPM formulae can be
demonstrated to be fair and reasonable to both utility owners and consumers.

Nevertheless, estimation of the WACC according to the methodology universally adopted
by Australian regulators requires consideration of the individual parameters. In this
respect, a major concern is that the approach used by ESC (and all other Australian)
regulators appears mechanistic and tends to focus on analysis of historical data in
determining values for individual CAPM parameters.

Further, the mechanistic approach where regulators follow the decisions made by one
another is more prone to perpetuating mistakes and diminishes the value of other
evidence available to regulators, such as the informed judgement of independent financial
market analysts which, for example, is typically given greater weight by UK regulators.43

In this context, it is noted that financial markets have been willing to continue to fund
energy networks in Australia and that financial market commentators have repeatedly
commented without undue concern about the impact on regulated utilities of regulators’
decisions.

The section below focus on the following individual parameters:
        the market risk premium (MRP);
        the risk free rate; and

43
     It is notable that OFWAT has formally acknowledged (in its recent Determination) that it has moved
away from reliance on CAPM to underpin judgements on WACC, and places greater weight on information
and observations obtain from financial market analysts and practitioners.



                                                                                                     30
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        equity beta.


4.4.1. Market Risk Premium

Of all the components of the WACC, the magnitude of the MRP attracts most
disagreement by practitioners and academics alike. Although ORG/ESC has previously
considered the merit of alternative bases and methods for deriving a value for the
premium, it is of concern that the current choice of 6% remains higher than it need be (to
satisfy the reasonable expectations of financial markets).

A primary concern is that reliance on historical approaches to calculating the MRP is
likely to provide estimates that are too high. Investors care about expected returns, not
historic returns. The market risk premium therefore should be estimated on a forward-
looking basis. Evidence from forward-looking studies almost universally show estimates,
on average, that are lower than that determined by arithmetic and statistical analysis of
historic data.

In addition, historical estimates differ considerably depending on the averaging technique
and time period used. The arithmetic mean is typically around two percentage points
higher than the geometric mean, depending on volatility and time period.44             The
statistical nature of the problem is such that an arithmetic average is likely to
overestimate the MRP. While it is beyond the scope of this paper (and resources
allocated to consumers for participation in the ESC review) to address this issue, the ESC
is urged to examine this issue more closely.

Historic returns are often used as a proxy for the expected forward-looking returns, which
is what CAPM is supposed to estimate. The main problem is that historic data cannot
measure the expectations of investors and historic data is therefore inconsistent with the
theoretical underpinnings of the CAPM. In particular, it is noted that Wright, Mason and
Miles (2003) say:45
            “It is evident that even over quite long periods, realised returns need not
            provide any relation to the expected premium. If they did, the experience
            of the bull market of the 1990s would have implied a risk premium of
            equities over cash of around 15%, switching to a large negative risk
            premium in the subsequent bear market of the early years of the new
            millennium. This would be manifestly absurd. There is no evidence that
            rational investors were expecting to receive such returns in advance.”

Further, there are reasons to believe the historic approach overestimates the return
required by investors:46

44
      See e.g. Wright, Mason and Miles (2003), A study into certain aspects of the cost of capital for
regulated utilities in the U.K., p 4.
45
       Wright, Mason and Miles (2003), A study into certain aspects of the cost of capital for regulated
utilities in the U.K., p 22. This report was commissioned by the UK economic regulators and the Office of
Fair Trading in order to gain an independent view on emerging and new issues in the estimation of the cost of
capital, the scope for greater consistency between regulators and to understand why there may be differences
in approach.
46
     For a comprehensive overview of factors affecting the Australian MRP, see Allen Consulting Group
(2004), Review of Studies Comparing International Regulatory Determinations, Report for the ACCC,
March.



                                                                                                          31
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        ex-post historical studies may be based on long time periods, but capital markets
        have changed substantially since 1900 and 1930 – and particularly in the past two
        decades. Financial markets have been liberalised, the Australian dollar floated,
        capital markets around the world have become less segmented and more integrated
        with world markets and the scope to diversify has increased substantially;47 and

        a downward shift in the MRP may be caused by improved regulatory and legal
        infrastructures that protect investors, by lower trading costs and by improved
        market liquidity.48

The ESC should therefore exercise care when using historical estimates as representative
of the current or recent situation, as they are likely to overestimate the MRP.49

Due to the perceived difficulties associated with collecting reliable prospective estimates
of the MRP, regulators have typically based their assessment on analysis of historic data.
However, the prospective approach is supported by several prominent economic experts,
for example Siegel (1992)50, Jenkinson (1993)51 and Blanchard (1993)52. Further, as a
result of the concerns about the validity of ex-post realised returns as an indicator of
future expectations, there has also been a general trend amongst UK regulators in recent
years to adopt more forward looking approaches to estimating the MRP. In particular, we
note that OFWAT and OFGEM are not the only UK regulators to consider both historical
and prospective evidence:53
        “In deciding the appropriate value for the equity premium, Oftel has taken
        account a range of evidence, both historical and forward-looking. Oftel’s
        judgement reflects its recognition of the need to balance both short and long
        run interests of consumers.”

The choices available to regulators are thus:
        to use a ‘firmly estimated’ but inappropriate historical measure;
        to use the ‘less firm’ measure, but appropriate forward-looking concept; or
        to interpret the range of estimates based on the inappropriate measure in the light of
        the insights from the forward looking results.



47
     See e.g. Ragunathan, V. (1999), The effect of financial deregulation on Integration: An Australian
Perspective, Journal of Economics and Business, 51, pp 505-674.
48
       A more complete list of factors is provided by AMP Henderson (2003), The equity risk premium – what
is it and is it enough? p 2-3.
49
     Further, the prospective method requires an assessment of expectation of the future equity market return
and is calculated by subtracting the risk free rate from the expected future market return. As such, it can
overcome the problem of consistency between the risk free rate and MRP.
50
     Siegel, J.J., (1992), The Equity Premium: Stock and Bond returns since 1802, Financial Analysts
Journal, Jan/Feb.
51
     Jenkinson, T. (1993), The Cost of Equity Finance: Conventional Wisdom Reconsidered, Stock
Exchange Quarterly, Autumn.
52
      Blanchard, O.J., (1993), Movements in the Equity Risk Premium, Brookings Papers on Economic
Activity, Vol. 2.
53
     OFTEL (2001), Proposals for network charge and retail price controls, Annex E, paragraph E.13,
February.



                                                                                                           32
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




A truly prospective and forward-looking approach should be favoured. The second best
solution, which is adopted by all UK regulators, is to explicitly place greater weight on
the available forward-looking estimates when deciding upon a range of values for the
MRP.

Based on the recent evidence provided by Allen Consulting Group54 and Professor Martin
Lally55, it can be suggested that the ESC could ‘safely’ reduce its estimate of the MRP
from 6% to 5% without disrupting the legitimate expectations of efficient financial
markets.56, 57 But this is not sufficient justification for imposing high and inefficient costs
onto consumers.

The solution for investors whose expectations exceed those of efficient financial markets
is to modify their expectations or transfer ownership of assets to investors whose
expectations represent those of efficient financial markets. If the DB owners are not
prepared to transfer ownership of assets to ‘efficient’ investors, then they should be
prepared to accept the same returns as ‘efficient’ investors. The ESC should not
overreact to pressure from businesses with a clear vested interest and seek to satisfy any
investor whose expectations exceed those of efficient financial markets. This would be
counter to, and inimical to, the intent of incentive-based regulation and good regulatory
practice.


4.4.2. Risk-free rate

It is also of concern with Australian regulators reject the use of a 5-year maturity
government bond to establish an estimate for the risk free rate. This is particularly
surprising given the very clear recommendations provided by Lally (2004)58 to the QCA,
and the QCA’s own belief that “there is strong case for setting the risk-free rate using a
bond-term equal to the length of the regulatory cycle”.59

The QCA reasons that the 10-year bond is appropriate because it is consistent with
standard commercial and regulatory practise (established by the ORG/ESC) and broadly
supported by stakeholders. This is distressingly similar to previous arguments put by
other regulators. This line of argument is symptomatic of the mechanistic and
conservative (i.e. overly protective of regulated monopolies’ interests) regulatory
approach taken by almost all Australian regulators.



54
     See Allen Consulting Group (2004), Review of Studies Comparing International Regulatory
Determinations, Report for the ACCC, March and Allen Consulting Group (2004), Queensland DBs: Cost of
Capital Study, A report to QCA, December.
55
     Lally (2004), The Cost of Capital for Regulated Entities, Report prepared for the QCA, October.
56
     It is noted that both ACG and Lally recommend a MRP of 6%. Nevertheless, interpretation of the data
provided, and weighting towards a forward looking approach to the estimation of the MRP, leads to a
conclusion that 5% would be a reasonable estimate.
57
      It is recognised that individual asset owners may express dissatisfaction with such a move. Epic
Energy’s reaction to the West Australian energy regulator’s attempt to establish a regulated price path for the
Dampier to Bunbury gas pipeline within reasonable proximity of an efficient cost base shows how strongly a
dissatisfied investor may react.
58
     Lally (2004), The Cost of Capital for Regulated Entities, Report prepared for the QCA, October.
59
     QCA(2004), Regulation of Electricity Distribution, Draft Determination, December, p 89.



                                                                                                            33
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Clearly, the most appropriate maturity to be selected is the 5-year government bond.
Simply because other Australian regulators have applied a 10-year maturity, or because it
is supported by regulated utilities, does not justify an approach that is clearly wrong. A
regular 5-yearly review of the DBs’ revenue requirement lowers the financing risk and
ensures the DBS will be able to finance assets with long lives.

The infrastructure necessary to support the provision of energy services is a long-term
investment and a long-term investor in that infrastructure has a legitimate commercial
interest to receive adequate compensation for the risks that it bears. The process of
regular regulatory reviews effectively transfers to risks associated with efficient
investment from shareholders to consumers. Accordingly, there is no legitimate
commercial interest in being compensated for risks which, as a result of the regulatory
scheme (or contract), are shifted on to others – specifically consumers. It is therefore
considered appropriate to adopt a five-year maturity as the maximum and appropriate
maturity for the risk free rate.

With regard to yields, theory predicts that current yields will reflect (all) expectations of
future earnings (if capital markets are efficient). Theoretically, it would therefore be
appropriate to select the most current yield.

However, current yields can be significantly affected by market influences in the short
term (e.g. thin trading) and be prone to significant cyclical variations. It is therefore
worthwhile to review the historical yields as these may be better predictors of future
yields than current yields. In our view, the current 20-day averaging period used by the
majority of Australian regulators, including the ESC, simply does not accord to such
principles. For example, over the last 2 years the 20-day moving average for indexed
Commonwealth Treasury Bonds has varied by nearly 100 basis points; and even over
short periods of several months, the 20-day moving average has fluctuated by 30 or more
basis points. This volatility has a significant effect on the estimated cost of debt that is
unrelated to financing costs for regulated utilities. It is notable that UK regulators
minimise this effect by taking a less ‘scientific’ approach and not ‘calculating’ a specific
value for the risk free rate. Instead, UK regulators place greater reliance on information
and advice sourced from financial market practitioners.

Hence, it is recommended that the ESC review how yields have fluctuated during the past
few years and consider the implications of any abnormalities in the daily yields for the
time period being considered that may lead to atypical results. The ESC will also need to
consider the implications for consumers of changing the basis for establishing the risk
free rate. It is clear that the DBs will have benefited over the current regulatory period
because Government Bond rates, and interest rates, have been markedly lower that
anticipated by the ORG in 2000. A simple mechanism to transfer these gains to
consumers is to maintain consistency in the method of establishing the risk free rate.


4.4.3. Equity Beta

The equity beta quantifies the relative risk to shareholders in the particular company, or
project, that reflects both the underlying risk of the project and the risk to shareholders as
a result of the – preferential claims of debt holders resulting from having leveraged the
balance sheet.




                                                                                            34
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Australian regulators generally rely on the recommendations of consultants in forming
judgement on the equity beta. Allen Consulting Group has provided advice to the
majority of Australian regulators on this matter. However, there are a number of
concerns with the ACG approach and its conclusions, most recently articulated in its
report to QCA:
        Based on a comparison with US data, ACG conclude that the equity beta would be
        in the range between 0.23 – 0.69. By removing ‘bubble’ data, ACG conclude that
        a current equity beta value is around 0.8.
        While the importance of eliminating the ‘bubble’ period is acknowledged, a simple
        method of doing this would be to rely on weekly observations instead of monthly
        observations that by definition require longer time series. By increasing the
        frequency of observations, the number of observations also increases, thereby
        reducing the variance/uncertainty of the estimate.60 That is, beta could be
        estimated on the basis of weekly (or even daily) observations using a short time
        period of say 1-2 years.
        ACG make no comparisons at all with UK regulatory decisions. This is surprising
        since the UK and Australia have similar regulatory regimes – and the vast majority
        of US jurisdictions still use ‘rate-of-return/cost-of-service’ regimes that would
        breach the National Electricity Code or Victorian Electricity Supply Industry Tariff
        Order if applied in by a regulator (and which deal with investment risk in
        fundamentally different ways to UK and Australian regulatory regimes).61 In this
        regard, it is noted that in its most recent decision, OFGEM has decided that an
        equity beta value of 0.8 is appropriate.62
        Without any adjustments for differing risk characteristics, ACG postulate an equity
        beta of 1.00, although its evidence would suggest a lower beta value. In the case of
        its recommendations to QCA, this value is then adjusted by 0.1 to take account of
        specific risk characteristics facing Queensland DBs (by contrast, in recent advice to
        the Economic Regulatory Authority of WA, ACG recommends an equity beta
        value of 1.0 simply because this is the value adopted by the majority of Australian
        regulators). Virtually all Australian regulators, including the ESC, acknowledge
        that evidence suggests an equity beta significantly lower than 1.0.
        We also note that ACG conclude that, “we would not expect the equity beta to be
        lower than that of say, metropolitan water distribution companies whose demand is
        largely dependant on weather conditions”.63



60
      However, it also increases the risk of serial correlation. Serial correlation of returns may be explained
by either overreaction by the market (giving rise to negative correlation), or rigidity (giving rise to negative
correlation).
61
     The US-style ‘rate-of-return’ schemes typically provide both an upper-bound and lower-bound cap of
equity returns, whereas the UK-style ‘incentive’ regimes provide opportunities for prudent, efficient and well-
managed firms to exceed the WACC benchmark. It is also noted that regulators administering UK-style
regimes have a key role in protecting the interests of consumers by not protecting imprudent, inefficient or
poorly-managed firms. Knowledge that regulators will not intervene to protect poor performers is a powerful
incentive for utility owners to insist on good performance by utility managers.
62
     Electricity Distribution Price Control Review - Final Proposals, OFGEM, November 2004 (Note
CAPM parameter values generally not quoted). See also Table 1, p.28, Electricity Distribution Price Control
Review. Background information on the cost of capital, OFGEM, March 2004.
63
     Queensland DBs: Cost of Capital Study, Allen Consulting Group report to QCA, December 2004.



                                                                                                             35
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        It is also noted that no Australian regulator has adopted a value for equity beta for
        the water sector above 0.9, with the lowest at just 0.4 – and the average shown for
        the Australian regulatory decisions in Appendix B of 0.73. Nor does it escape
        attention that the ESC only recently adopted an equity beta value of 0.75 for
        Victorian water businesses. There appears to be no clear argument why a higher
        value is either appropriate or suitable for application to energy utilities.

In summary, there is no convincing evidence that a value of 1.0 is appropriate for the
DBs. This is an overly conservative estimate and a lower value should be adopted.
Indeed, it is suggested that the ESC answer the following question:



What are the similarities between monopoly utilities and firms in competitive markets that
support the judgement that non-diversifiable risk faced by those utilities is exactly the
same as the financial market as a whole? OR: Why should Equity Beta value be set at (or
near) 1.0 for monopoly utilities that provide what are effectively price-inelastic “essential
services” that consumers literally cannot do without or get elsewhere?

A first principle evaluation of the risks faced by the DBs is likely to reveal that the equity
beta values are lower than 1.0. Indeed, evidence suggests values no higher than 0.7 – 0.9
to be reasonable. As such, it is suggested that the ESC adopt an equity beta of no more
than 0.8, or around the same value adopted for regulation of the water sector.


4.5. Choice of Model

Virtually every Australian regulator has its own preferred CAPM model. The ESC uses
what it calls the “Vanilla”, real, post-tax version. QCA uses what it calls the “Officer
WACC3” CAPM to determine WACC. IPART, ICRC, ESCoSA, ERA and OTER all
continue to use the much more complex pre-tax version. It is noted that the “Officer
WACC3” model is very similar to the “Vanilla” version of CAPM adopted by ORG in
2000 and used to ‘benchmark’ WACC in the section above.

It is common for Australian regulators to rely on domestic closed economy versions of
the CAPM, even though it is widely recognised that the Australian economy is open and
increasingly so. With regard to capital integration, the change from a segmentation to an
integration approach to estimating WACC has been examined by Jorion and Schwartz
(1986)64 for Canada and by Ragunathan (1999)65 and Ragunathan et al (2000)66 for
Australia.

Betas and MRPs must be defined against the market to which they apply. Importantly,
both the betas and MRPs change as markets become more integrated and investors are
able to diversify more and more.

64
      Jorion, P. and E. Schwartz, (1986) Integration vs. Segmentation in the Canadian Stock Market, Journal
of Finance, 41, pp. 603-616.
65
     Ragunathan, V. (1999), The Effect of Financial Deregulation on Integration: An Australian Perspective,
Journal of Economics and Business, 51, pp. 505-674.
66
    Ragunathan, V., Faff, R. W., and Brooks, R.D., (2000), Australian industry beta risk, the choice of
market index and business cycles, Applied Financial Economics, 10.



                                                                                                         36
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Econometric analysis by Ragunathan et al (2000)67 finds that Australian betas are best
explained when the influence of both Australian and US market portfolios are recognised.

An appropriate method of responding to the concern that Australian estimates of the MRP
may be invalidated by the step change from a segmented capital market to a more
integrated international capital market would be to:
        rely on forward looking estimates of the Australian MRP. By definition these are
        free of the step change which occurred with the float of the Australian dollar and
        financial market deregulation. This approach would allow the segmented CAPM
        model to continue to be applied but would avoid any concerns with estimate bias
        due to greater integration; or
        recognise that capital markets have become increasingly integrated and adopt an
        integrated/international CAPM approach in conjunction with a segmented
        approach.

The first option would result in a reduction of the estimates of the MRP (as discussed in
section 4.4.1)

The second option is likely to result in significantly lower estimates of the appropriate
MRP, beta and therefore the WACC.

While the use of an international CAPM potentially would increase complexity and
reduce reliability, this in itself should not imply that insights from the international model
should not be used in the regulatory process. It would serve to illustrate an important
point: that recognition of the consequences of capital market integration will result in a
WACC that is lower than currently suggested by Australian regulators.

Since the world portfolio offers opportunities to diversify across economies, the variance
of the world portfolio is less than the domestic portfolio. As a result, the world MRP is
lower than the Australian MRP. Lally (2000) calculates that the world MRP of 3.5% is
appropriate.68


4.6. Conclusion

The benchmark material presented above provides a comparison of estimates for the cost
of debt and the return on equity indicated by decisions of regulators in the UK and
Australia. These estimates have been derived using values judged by each regulator as
being appropriate for individual parameters required for use of the simple, “Vanilla”, real,
post-tax form of the CAPM (noting that the individual parameters, and the values
assigned to them, are the same in each version of CAPM – unless account is taken of the
degree of market integration/segregation). All estimates are expressed in common
‘apples-for-apples’ real, post-tax terms.

Analysis of this material clearly shows that Australian regulators historically have
accepted a significantly lesser difference in the cost of debt (in real terms) between the
UK and Australia than is the case for cost of equity (or return on equity). That is, the

67
     Ibid p 49
68
     Lally, M (2000) The Real Cost of Capital in New Zealand: Is it too high?, October.



                                                                                            37
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




judgement of Australian regulators is that the debt market sees a (very much) smaller
difference between Australian and UK utilities than does the equity market. This
judgement may be sound, but the magnitude of the difference - and the spread of values
for estimated return on equity by Australian regulators - is substantial. While this
difference has not been adequately explained in regulatory decisions, recent evidence
from the UK suggests that differences between the countries may, in fact, be narrowing.

While this latest evidence is encouraging, as international financial markets would be
expected to see similar regulated utilities in consistent terms, the latest determinations
from the UK also suggest that changes have been influenced by relentless lobbying of
utilities rather than an underlying change in financial market fundamentals. As such, it is
noteworthy that the 1994 and 1999 decisions by OFWAT were subject to appeal, while
the 2004 determination was not, which suggests the UK water industry was well satisfied
with the outcome.

It is clear that the dominant ‘regulatory principle’ governing the treatment of WACC
should be that the return on equity and cost of capital be set at levels that meet the
reasonable ‘efficient’ expectations of financial markets – rather than individual investors.
This is what is intended by the regulatory regime and the only way that consumers can
access the benefits of ‘efficient’ financing of prudent, well-managed companies by
providers of capital whose expectations are reasonable. On the other hand, continuing to
set WACC values that are inflated and biased in favour of utilities holds out no prospect
of consumers being able to share in efficiency benefits through incentive regulation, as
required by the Tariff Order and Victorian legislation under which the ESC regulates
electricity distribution.

It is accepted that the ESC’s regulatory decision is likely to be based on a wide range of
information – and that the ESC will attempt to promote ‘regulatory consistency’ as a
desirable goal. However, it is of concern that insufficient attention will be paid by the
ESC to evidence from the UK. Further, it seems that the ‘principle’ of regulatory
consistency prevails over the need to arrive at fair and reasonable judgements based on
the best available information. An example is the choice of a 10-year maturity of the
risk-free rate that QCA clearly recognises is inappropriate.

The major cause of the differences between estimates for the cost of equity between the
UK and Australian regulatory judgements seems to be that Australian regulators have
accepted higher values for the MRP than do UK regulators; and higher - and much more
varied - values of equity beta.

In general, Australian regulators have relied on historical evidence to determine the MRP.
However, in addition to being inconsistent with approaches that seek to access forward-
looking information to estimate the cost of capital, historical analysis will bias the
estimate of the MRP upwards due to the fundamental changes to the financial markets
during the past 50 years. A reasonable view is that the ESC should rely more heavily on
forward-looking estimates and information provided by experienced financial market
observers and practitioners who have no self-interest to promote.

An alternative option is for the ESC to cross-check current estimates of the WACC with
estimates based on an international version of the CAPM where markets are integrated.
For an open economy, such as Australia, regulators need not choose one or the other of
the segmented or integrated versions of CAPM. Rather, they should examine both, on an


                                                                                          38
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




internally consistent basis, and then determine a preferred estimate between the two
extremes represented by each model.

If regulators fail to accept this view and a domestic version only is used, the bias
imported to the resulting WACC estimate (as a result of model choice) should be clearly
acknowledged.

The current outcome is that all Australian regulators, particularly the ESC and ACCC, are
making decisions and judgements for energy utilities that are excessively conservative
and to the detriment of consumers.

The evidence from recent decisions included above show that UK regulators, and UK
financial markets, accept that ‘market expectations’ are different to historical ‘evidence’.
They also accept that all regulated utility sectors present similar risks that are
significantly lower than the market as a whole (although, in common with Australian
regulators, the UK regulators insist on adopting values they openly acknowledge are
‘conservative’ – so as not to act as a disincentive for investment).

Australian regulators, by comparison, continue to ignore the UK precedents and also
continue to come down with markedly different judgements on the value of WACC for
different utility sectors and even the same sectors in different jurisdictions.

Recent decisions in Australia also show strong segregation between the ORG/ESC and
other jurisdictional regulators. The ORG/ESC’s decisions for electricity and gas provide
significantly greater returns than almost all other jurisdictions; and all regulators continue
to set higher WACC values for energy utilities than water utilities even though risk
profiles would appear to be similar. The difference between ORG/ESC judgements and
(most) other Australian regulators is costing consumers in the order of $55 million per
year.

Given the high cost for consumers of its previous decisions on WACC, the ESC needs to
explain why it should continue to:
        adopt a different approach to setting a value for MRP than UK regulators;
        adopt higher WACC values for energy utilities than virtually all other Australian
        jurisdictional regulators; and
        adopt higher values for energy utilities than for water utilities.

It seems reasonable to suggest that the ESC set WACC for the Victorian DBs in the range
as low as 5.0% and certainly no higher than 6.0% thus allowing consumers to gain the
benefits of efficient financing of energy utilities.




                                                                                            39
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




5. Interval Meter Roll-out
The ESC has commissioned consultants ECG to review the DBs’ meter rollout proposals,
and this review is still underway. The ESC advised in the Position Paper that ECG’s
findings will not be available until the Draft Determination is published in early June.
Therefore it is not possible to make any detailed comments on the ECG findings.


5.1.      Interval Meter Costs
However, as shown in the Table below, the total capital requirement forecast by the DBs
for the interval meter rollout mandated by the ESC is considerable. The total figures are
for costs incurred in the 5 year regulatory period, although the rollout program is intended
to extend a further 2 years to 2012. Most of the cost is attributed to the meter installation
process.

TABLE 2: FORECAST METERING CAPEX ($JUN04)
                               2006        2007       2008        2009        2010       Total
                AGLE          $13.2        $7.8       $9.4       $19.6       $20.5       $70.5
                  CPL         $11.3       $15.0      $15.0       $14.7       $16.6       $72.6
                  PCL         $17.8       $29.4      $44.8       $42.8       $45.7      $180.6
              SPI/TXU         $94.6       $95.8      $47.9       $31.1       $16.2      $285.6
                  UEL         $25.5       $14.5      $45.3       $24.7       $26.6      $136.6
Total Metering CAPEX         $162.4      $162.4     $162.5      $133.0      $125.6      $745.9
Note: Includes meter, installation and IT system costs. Some assumptions were required in interpreting DBs’
proposals. Not all DBs disclose full details of CAPEX, O&M, IT costs, revenue attributed to metering and
Excluded Service Charges. The total number of meters to be installed over the five-year regulatory period is
around 1.15 million giving an average total cost of $647.40.69

The revised meter rollout costs presented in the ESC Position Paper result in forecast
(incremental) metering services revenue growing for a total of $61.3M in 2006 up to
$175.6M in 2010 (and $207M by 2012).70 This translates into an incremental additional
price impost between $5.22/year and $54.26/year for single phase meters.71

It is difficult to understand why the DBs’ proposed interval metering costs are so high.
The total cost of the meter and installation is about 4 to 6 times the average total cost of

69
     It is noted that the ESC Position Paper provides updated information on meter numbers (pp201-202)
and meter installation costs (p207), but only in Bar Chart form. Meter numbers are not shown by consumer
segment, but by meter program classification and meter type. It is not possible to make any accurate
comment on average costs by consumer segment.
The total number of meters indicated from the Charts remains around 1.63 million, of which around 1.2
million are single phase. These meters are to be rolled out in a 7-year program from 2006-2012. There is no
indication of how many old-style accumulation meters will remain in service after 2012.
Average “unit costs”, excluding O&M and IT costs, appear to be around $350 (range $250-$550) for “single
phase non-off peak meters” and $450 (range $180-$850) for “single phase off-peak meters”. An additional
total amount of around $100M is proposed for IT system costs (p214), and a further $28M for “indirect costs
allocated to the metering price control” (p216), with O&M costs totalling around $6.4M/year (p209). These
additional costs give an indicative average of around $100/meter spread of the 7-year roll-out.
The overall indicated average cost appears to be around $500/meter all up for single-phase meters.
70
     Table 12.4, p220.
71
     Table 12.5, p220.



                                                                                                          40
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




the ENEL roll-out in Italy, which not only includes an interval meter but also
sophisticated two-way powerline carrier communications technology with capability to
offer interactive load control, and the IT systems required to handle all the data.72

The DBs meter roll-out costs also appear to be up to 3 times higher than the Ontario
Electricity Distributors’ Association estimates for a Victorian-scale interval meter roll-out
of 800,000 meters over 3 years (and the Ontario costs include Stranded Asset recovery
and interval meters capital costs that appear much higher than equivalent meters in
Australia).73

The ENEL roll-out does offer opportunities to exploit economies of scale that could not
be achieved by any of the Victorian DBs, but it is inconceivable that a unit cost up to
600% higher could be efficient even for a smaller scale roll-out.

Nor is it clear what is to happen to those consumers who retain standard accumulation
meters. About 1.63 million meters are to be rolled out over six years (to 2012), which
suggests half a million consumers will not have meters (unless these customers already
have interval meters that have been installed at the last for a five years - see next point).

This is one of the matters that will, hopefully, be clarified in ECG’s review for the ESC.
However, the DBs say nothing about Australian meter manufacturers not making
electronic accumulation meters for several years. It is understood that any new electronic
meter installed since (around) 2001 is very likely to have been interval-meter capable
even if it is only being read as an accumulation meter. Information from Australian meter
manufacturers suggests at least 200-300,000 interval meters suitable for Residential
consumers, both single and double element, have already been rolled-out in Victoria –
within the current regulated revenue benchmarks. This begs the question as to why costs
for the remaining roll-out should be so high.

It is also of concern that:
         The time to complete the roll-out is relatively long, as it will not start until 2006
         and is to extend to 2012. By comparison:



72
      See: ENEL Telegestore Project is on Track, Vincenzo Cannatelli – Enel Group, Italy. Metering
International, Issue 1, 2004.
This article confirms information provided to Pareto Associates by ENEL some years ago, that the meter and
associated powerline carrier communications hardware costs of the ENEL roll-out were in the order of US$65
per installation. ENEL also confirmed the average installation cost could be around US$20 per meter.
73
     See: http://www.eda-on.ca/eda/edaweb.nsf/0/C132012C8366C33085256F4A0072C976
The Ontario Electricity Distributors’ Association claims that the average all-up cost of the interval meter roll-
out (including the Stranded Asset cost of existing meters) is in the range CA$315-325, with the capital cost of
an "interval meter" estimated to be CA$250.00. The meter costs is substantially more than AU$65 for an
Email-Ampy single element P1 or AU$130 for a two-element A11L with 70A hot-water switch, which are
indicated costs in Australia. Substituting the CA$250 meter cost for (say) CA$100 for a dual element interval
meter in large volumes in Australia would reduce the total roll-out average cost to about CA$160-185/meter -
including recovery of Stranded Assets.
If the Stranded Asset cost is removed (to allow for recovery by the Victorian DBs of Stranded Assets through
DUoS), and a "sensible" capital cost for the new interval meters included, the Ontario unit cost reduces by
about another CA$30 to CA$130-155 (or AU$135-160/meter).
This is in the order of AU$500/meter lower than the costs indicated in the DBs’ proposals - and not all that
much higher than the unit costs of the very much larger volume ENEL roll-out.



                                                                                                              41
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        −     ENEL expects to complete its roll-out within 3-4 years (and achieve a payback
              of the US$2 billion investment cost in less than 5 years from improvements in
              its distribution and retail business);
        −     The initial phase of the Ontario roll-out (800,000 meters) is to be completed
              by 2007, with the remaining 3.5 million completed by 2010.
        Only Citipower and Powercor are proposing to install (mid 20th Century) ripple
        control technology for a total cost of about $45 million. But there is no indication
        of how this will be used or how many consumers would benefit from any
        additional service.
        None of the DBs propose to trial sophisticated two-way communications and load
        control capability similar to that being rolled out in Italy and Ontario. (Apart from
        allowing for the possibility of installing communications capable meters, and
        possibly installing meters with switches suitable for remote control of AC load.)
        It is particularly disturbing that the ESC’s initial position is that: “No submissions
        indicated that customers were (1) willing to have loads controlled by the
        distributor, and (2) prepared to pay the additional cost for the “ripple control”
        technology.
        Accordingly, the Commission’s preliminary view is that the expenditure for “ripple
        control” technology should not be provided in the revenue requirement. However,
        where the benefits exceed the costs, the distributor may choose to install this
        technology. Additionally, such innovations may evolve through a more competitive
        metering market.”74
        The ESC has, in fact, received a number of submissions from consumer groups
        since 2000 suggesting that remote load control should be examined closely.75 This
        is particularly because application of time-of-use tariffs, similar to United
        Energy’s, will adversely impact large numbers of AC-using consumers.76
        Without automatic load control capability, adversely affected consumers have few
        choices – apart from denying themselves use of the ACs – if they wish to avoid
        substantially higher bills. If this generates adverse consumer reaction, which is
        very likely, the ESC may be moved to impose transitional arrangements or tariff
        design constraints on the DBs (and even retailers) which will drag out achievement
        of the benefits of interval metering over even longer time frames than already
74
     p225, ESC Position Paper.
75
     At least three of these are:
Smart Meters for Smart competition - Handing Back Power to Consumers, Comment on Current Policy
Affecting Interval Metering and Load Profiling for Full Retail Competition in Electricity, Pareto Associates
Pty Ltd. Report for the Customer Energy Coalition, May 2001.
Smart Meters for Smart Competition? Will Current Proposals Hand Back Power to Consumers? Update
2003 A consumer-focussed comment on the Victorian Essential Services Commission Position Paper
Installing Interval Meters for Electricity Customers - Costs and Benefits, Report For The Energy Action
Group, Pareto Associates Pty Ltd, March 2003; and
Customer Impacts of 2001 Electricity Distribution Price Review, Report to the Consumer Utility Advocacy
Centre from Customer Energy Coalition, Pareto Associates Pty Ltd, September 2003.
76
     The three reports above demonstrate that United Energy’s network tariffs have a dramatic impact on
AC-using consumers, raising total costs by hundreds of dollars per year for moderate AC loads of 2-4kW.
The only reasons this has not become an issue already is that ORG’s 2000 Determination prevents
compulsory re-assignment of consumers to United tariffs just because of a meter change and no retailer offers
a matching product that reflects the costs of United time-of-use tariffs.



                                                                                                           42
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        anticipated. This would be a very poor outcome for consumers forced (by the
        ESC) to bear higher costs.
        None of the other DBs propose to follow United Energy's example and introduce a
        range of cost reflective, time-of-use tariffs that would apply to all customers with
        interval meters. Only one or two DBs (vaguely) mention revising their tariff
        structures during next regulatory period. Other DBs will leave tariff redesign until
        all meters are rolled-out, that is after 2012.
        The ESC has no powers to determine whether or not retailers develop time-of-use
        tariffs, which would deliver the cost and/or benefits of cost reflective, time of use
        network tariffs to the affected consumers.
        In addition, several DBs refer to the rules contained in the ORG’s 2000
        Determination that (supposedly) prevent compulsory assignment of existing
        customers to new network tariffs unless that is a significant change in load type or
        characteristic.77

Again, it is particularly disturbing to note that the ESC proposes to “allow distributors to
mandate the re-assignment of customers where distributors have installed an interval
meter. Such re-assignment would occur where an interval meter has been installed
and/or a change in a distribution customer’s load and/or connection characteristics has
occurred.”78

It may be some comfort to consumers that the ESC “remains of the view that some form
of consultation with customers is required prior to any re-assignment occurring.”
However:
        the proposed method of addressing this is likely to impose substantial demands on
        consumer groups which the ESC must address because the ESC “is proposing to
        establish, at the conclusion of this price review, a working group comprising
        representatives of the Commission, distributors, retailers, end-user representatives
        and relevant Victorian departments to develop transitional arrangements for the
        rollout of interval meters;” and
        the ESC rejected a sensible suggestion from CUAC that tariff designs be guided by
        more than addition of one general criterion “that tariffs should signal the impact of
        additional (peak) usage on future investment costs”79 to the lower and upper bound
        economic efficiency criteria of ‘marginal cost’ and ‘bypass cost’ specified in
        ORG’s 2000 Decision.

The time-of use interval meter tariffs introduced by United Energy in 2001 are intended,
and appear to, effectively “signal the impact of additional (peak) usage of future
investment costs.” Given that wider introduction of similar tariffs (reflected in retail
tariffs) will have dramatic impacts on small consumers, the ESC must do more than


77
      It is not at all clear that these ‘rules’ offer protection to consumers. The 2003 Pareto Associates Pty Ltd
report to the Customer Energy Coalition refers to specific examples listed in the DB Tariff Reports that
suggest these “rules” are interpreted so as to benefit the DBs. (See: Customer Impacts of 2001 Electricity
Distribution Price Review, Report to the Consumer Utility Advocacy Centre from Customer Energy
Coalition, Pareto Associates Pty Ltd, September 2003).
78
     p188, ESC Position Paper.
79
     p191, ESC Position Paper.



                                                                                                              43
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




consult on the issue and reject any consideration of rolling out automatic load control
technologies with interval meters.


5.2.      Impact on consumers
Neither of the ESC’s Papers clearly identifies the cost impact on individual consumers of
the interval meter roll-out, and what information is provided is confusingly presented.

Interval meter revenue is shown for small consumers,80 but not for large consumers; and
the annual metering charges for small consumers proposed by different DBs (for exactly
the same service) are all over the place.81 Nor is it entirely clear what these prices relate
to. The ESC says "it is proposed that customers with an annual consumption of less than
160 MWh that utilise the metering services provided by the distributor will pay charges
under the metering price control" but shows the charges as "Meter Provision" and
"Metering Data Services" that appear to be unconnected.

The revenue for small consumer interval metering is shown rising from $61.3M in 2006
to $175.6M in 2010 (and $207M in 2012). Preliminary estimates of total tariff revenue
without interval metering are shown in Figure 3 of this submission.82 Comparison of
these tow data sets suggests interval meter revenue rises from about 4.2% of non-interval
meter revenue in 2006 to about 10% of non-interval meter revenue in 2010. Of course,
all customers are also still paying for the stranded accumulation meters in their tariff
revenue - but nowhere does the ESC say how much of the non0interval meter revenue
this comprises..

The "Meter Provision" charges quoted by the ESC range from $4.54/y for TXU (1 phase
non off-peak) to $54.26/y for AGL (1 phase off-peak). But it is note entirely clear how
the ESC (or DBs) derived these figures. They could be the average cost paid by all
consumers to cover the costs incurred in metering just some.

Even so, an average small consumer with hot water would probably have a bill of around
$800-1000/year, which suggests AGL's price would add up to 5 -8% to their bill. A small
consumer without hot water (around average consumption) would pay around $500-700,
and the interval meter charge would appear to add between 1% and 2.5% to their bill.
However, few of these consumers not to have an interval meter installed under the ESC’s
roll-out priorities.

It is also noted that, among other things, the ESC’s proposed interval meter working
group would be involved in developing “a hypothetical bill demonstrating what impact
the introduction of interval meter tariffs will have upon the average household or
business bill”. The ESC needs to do much better than this.



80
     See Table 12.4, p220 ESC Position Paper.
81
     See Table 12.5, p220 ESC Position Paper.
82
      Figure 3 shows preliminary estimates of revenue with and without interval metering. As stated in the
text the interval meter revenue estimates were based on some assumptions because the initial DB submissions
did not provide sufficient data to determine the revenue for all DBs. It is noted that the figures shown in
Figure 3 are not the same as the ESC's figures in Table 12.4 of the Position Paper (although they are not
wildly different)



                                                                                                         44
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




At the level of average cost indicated of around $500-$650 per metering installation over
the five year period, it is likely that Residential consumers would receive significantly
less benefit from the interval meter rollout than might otherwise be the case. Residential
consumers are unlikely to benefit overall at this level of average cost.

This conclusion is supported by detailed analysis of a small set (ten in all) of individual
Residential consumer interval meter undertaken by Pareto Associates Pty Ltd (Pareto)83
in 2003. It should be noted that each of the reports containing information on this
analysis has been submitted to the ESC, and formal presentations made to the ESC’s
Customer Consultative Committee on some.

Pareto used actual interval meter data provided by one of Victoria’s major energy
retailers84 and applied United Energy’s interval meter time-of-use tariffs to the recorded
load profile. In very brief summary, this showed that:
        Residential consumers on (near) average consumption with air-conditioning would
        face higher total annual bills (up 3.3% to 24% for a 2kW AC load; and 32% to 40%
        for a 4kW AC load);
        this cost impact may only be mitigated if the AC users they were also big users of
        Off-Peak energy (and their AC load was moderate (less than 4kW); and
        Residential consumers without AC could achieve annual savings of between 10%
        and 28%.

In each of the data sets analysed, consumers without AC were better off − with reductions
in total bills ranging from around $130/year for a moderate (about average) household to
over $500/year for a large energy consuming household (about 3 times average) with Off-
Peak hot water. However, this analysis assumed no increase in metering costs and took
no account of the fact that AC penetration had (by 2003) reached around 50% of
households in all income groups.85

A particularly interesting feature of the analysis was the very different financial impact on
households with similar AC demand and similar total annual consumption.                 This
reflected whether or not the AC was used during the periods nominated by United for
imposition of the Summer Demand Incentive Charge (SDIC).86

83
      Smart Meters for Smart Competition? Will Current Proposals Hand Back Power to Consumers? Update
2003 A consumer-focussed comment on the Victorian Essential Services Commission Position Paper
Installing Interval Meters for Electricity Customers - Costs and Benefits, Report For The Energy Action
Group, Pareto Associates Pty Ltd, March 2003; and
p13, Customer Impacts of 2001 Electricity Distribution Price Review, Report to the Consumer Utility
Advocacy Centre from Customer Energy Coalition, Pareto Associates Pty Ltd, September 2003.
84
     The interval meter data sets were selected by the retailer to represent “typical” consumers, with both
“normal” and “large” annual consumption. There were four basically different consumer cohorts represented
(1) No AC; (2), No AC and no Off-Peak hot water; (3) AC; and (4) AC and Off-Peak hot water.
85
     ABS surveys on AC use were undertaken in June 1994, March 1999 and March 2002. These surveys
show AC penetration increasing in all jurisdictions. 52.9% of Victorian dwellings had ACs in the 2002
survey, up from 26.9% in 1994 (see Table 4.16, ABS 4602.0 Environmental Issues - People's Views and
Practices.). At least 66% of all ACs in Victoria were (higher energy using) reverse-cycle or refrigerative
models (See Table 4.17).
86
      The United Energy tariffs are relatively complex. The SDIC is incurred on the highest half-hour in each
billing period between 3:00PM to 6:00PM on Working Week Days from 1 November through 31 March for
the RCAC and kWh-TOU tariffs; and 3:00PM to 6:00Pm on Working Week Days over 35°C for the kWh-
TOU-HOT tariff.



                                                                                                           45
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Residential consumers without hot water or air-conditioning (AC) on average
consumption may still achieve overall benefit that exceeds the proposed interval meter
cost levels, but this is by no means certain. For example, as mentioned above other
distributors have so far indicated to the ESC that they are not planning to follow United’s
lead and develop identical tariff structures and designs during the next regulatory period –
and not one retailer has developed a tariff that passes on the benefits and costs of United
Energy’s ToU tariffs to affected consumers – even though United has been ‘offering’
these tariffs since 2001.

The DBs’ proposals seem out of touch with ESC's Final Decision on interval metering. A
few quotes from the ESC's decision illustrate this:

        "Modern interval meters are the building blocks that will facilitate
        developments in a wide range of complementary products and services."

        "The Commission has also varied the draft decision in respect of the
        communication capability of the interval meters. All meters are to be
        communication enabled (utilising ‘open systems architecture’) to ensure that
        the meter can facilitate remote reading without the need for a further meter
        changeover."

However, the DBs’ proposals suggest that:
        The ‘market’ will have to provide the communications capability/load control
        functionality that would enable more convenient (for consumers) delivery of
        potential interval meter benefits. But
        −     without convenient, automatic, remote load control (which, as the Ontario
              government and ENEL have recognised, would be able to be most efficiently
              installed by DBs), capture of whatever benefits are offered by retailers could
              only flow to non-AC users and any AC users who manually choose not to be
              cool when it is hot; and
        −     neither the ESC’s Interval Meter Decision, nor the DBs’ proposals specifically
              target AC users (who are those driving substantial costs in all sectors of the
              electricity supply chain);


It should be noted that the SDIC charge accounted for up to 1/3rd of the total bill in the interval meter data sets
that were analysed by Pareto. Sensitivity analysis undertaken by Pareto also showed that load management
during the SDIC charging time periods could have a substantial impact on the total bill amount. As Pareto
noted:
     Of course, tariffs such as those implemented by United are not all bad news for consumers.
     Consumers who are able to shift significant consumption (and half-hourly demand) past 7:00PM
     may achieve substantial savings in their bills. But to be successful they would have to ensure they
     did this every Working Week Day in each billing period from 1 November through 31 March. If they
     missed load shifting just one Working Week Day they would incur the SDIC charge for the whole
     billing period. This is because the United SDIC charge applies to the highest half-hourly demand
     between 3:00PM and 6:00PM in any Working Week Day in the billing period.
     A consumer who succeeded in shifting/curtailing load nearly every Working Week Day would not
     avoid the charge. That is economically rational, but it is unarguably a very high hurdle. No
     reasonable household could ever expect to achieve that goal using manual load control.
(pp 31-32, Smart Meters for Smart Competition? Will Current Proposals Hand Back Power to Consumers?
Update 2003 A consumer-focussed comment on the Victorian Essential Services Commission Position Paper
Installing Interval Meters for Electricity Customers - Costs and Benefits, Pareto Associates Pty Ltd, March
2003).



                                                                                                                46
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        The extended roll-out period will allow at least another decade to develop the full
        effect of AC load, which will drive billions of dollars in sub-optimal investment in
        generation, transmission and distribution; and
        Interval Meter charges will be Excluded Services Charges - and all other DBs will
        be able to join United Energy and claim in their Tariff Reports that Fixed Costs
        have been reduced (possibly to zero) when, in fact, consumers look certain to be
        subject to substantially higher fixed Excluded Service Charges for interval
        meters.87
        The ESC is proposing an "M Factor" to “bribe” DBs to roll-out interval meters
        (and make interpretation of regulatory outcomes even more complex).


5.3.      Problems with the DBs’ Response to the ESC Interval
          Metering Program
Another difficulty with the DBs’ proposals for the interval meter rollout is that there is
nothing which clearly outlines how consumers would benefit from this program. The
DBs are proposing the minimum required to meet the program imposed on them by ESC
(with what appears to be substantial padding of the cost forecasts).

Fundamental problems with the ESC's program, and the DBs’ responses, are:
        there is no attempt to assign interval meters to consumers with AC, even though all
        the DBs confirm either directly or indirectly that it is those consumers that are
        driving substantial costs - and the need to invest in more network capacity; and
        the proposal to offer incentives for the DBs to meet the ESC's program will
        increase costs to consumers.

The flaws in the strategic framework for the interval meter rollout mean that it is much
less likely that consumers will gain any benefit overall, particularly since the proposed
Excluded Service Charges applying to interval metered consumers appear to be more than
100% higher than the metering charges currently imposed for accumulation meters.

The obvious strategic flaws in this program will almost certainly impact in a negative
sense on all consumers who do not contribute to AC demand in a significant way. This
includes low-income households without AC, households with small AC units (less than
2 kW demand) and business consumers (small and large) with substantially better load
profiles than AC using households. The lack of regulatory specification, or regulatory
oversight of cost allocation methodologies and detailed tariff designs means that it is
impossible to be sure that these consumers will not bear at least part of the increased cost
of providing the capacity to meet increasing AC demand.



87
     We note that the ESC acknowledges that the requirement, imposed by ORG in 2000, for DBs to prepare
Annual Tariff Reports “does not adequately assist customers to understand tariff structures, the cost
allocation underlying them or the movement in tariffs over time”, which is an understatement.
The ESC’s proposal is to also require the DBs to produce a 5-year, overarching, Tariff Strategy Report. It is
not clear this will improve transparency of pricing information for consumers unless it integrates tariffs and
Excluded Service Charges, and shows meaningful details on the actual costs allocated to each tariff and
Excluded Service Charge in a way that can be directly compared with information on a consumer’s bill.



                                                                                                            47
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Another issue that requires further clarification is what is driving the forecast cost of
meter installation. For example, TXU says it will cost $129.74 to install a single phase,
single element meter (plus $15.98 in Back Office (Install) – what ever that means) and
$142.74 (plus $23.98), for what is presumed to be a single phase, two element meter (for
Off-Peak hot water). Direct observation of a meter installation shows that it is possible to
install a single phase, two element interval meter (not requiring any re-wiring or
connection to a hot water circuit) in a matter of minutes.88 A reasonably designed
installation program should allow significant numbers of meters to be installed in a single
visit to one ‘precinct’ in a DBs supply territory (even if not all meters are replaced in a
single precinct).

It appears clearly that the DBs are including a substantial element of ‘monopoly’ cost
padding, or significant inefficiencies, in their interval meter roll out costs. Either way it
would be highly inappropriate for the ESC to accept these costs as the stand. The ESC
needs to require the DBs to provide much greater information to show how much of the
installation cost is related to:
        re-wiring of meter boards to accommodate the simpler, single meter installation
        compared to 2 meter plus separate time-switch of conventional Off-Peak hot water
        metering installation;
        rewiring to achieve compliance with current Electrical Safety Standards, where an
        existing metering installation is found to be non-compliant;
        replacement of asbestos-cement meter board; and
        proof that the meter installation program is planned so as to minimise the total
        cost.89


5.4.      Improve the Tariff Reports
The proposals to exclude metering costs from regulated revenue and charge for metering
as an Excluded Service Charge will mean, if nothing changes in the Tariff Report
arrangements, the metering charge will not show up in the Tariff Report. This means that
the Tariff Reports are of limited practical use to any consumer who pays an Excluded
Service Charge as part of the regular bill.

Another issue identified in the 2003 report by Pareto Associates for the Customer Energy
Coalition was that the treatment of metering costs as Excluded Services (in the case of
United Energy) allowed United to claim that it had eliminated fixed charges from its
interval meter tariffs, when in fact it allocated a separate Excluded Service Charge for the

88
      Australian standards require all meters to be constructed with connection points that align with those
specified in the (DBs) Victorian Service and Installation Rules. Therefore it is possible to simply remove and
old meter and replace it with a new meter without any major reconfiguration of the meter board. All
installations with electronic meters, or single phase, single element Ferraris disk meters, should be capable of
change-over without reconfiguring of the meter board.
However, it is acknowledged that older metering installations supplying Off-Peak loads will have to be
reconfigured once the electromechanical time switch and Off-Peak Ferraris Disk meter are removed.
89
   For example, ENEL (the Italian electricity utility) has reported it has achieved an installation rate of
700,000 per month for its much more advanced metering and two-way communications system. (See: ENEL
Telegestore Project is on Track, pp16-21 by Vincenzo Cannatelli – Enel Group, Italy, Metering International,
Issue 1, 2004).



                                                                                                             48
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




metering component which was higher than the fixed quarterly charge for a standard
metered customer.

It is not at all clear that the ESC’s proposal to require the DBs to also produce a 5-year,
overarching Tariff Strategy Report will improve the situation for consumers unless this
report (or the Annual Tariff Reports) includes full disclosure of:
        All tariff and Excluded Service Charges;
        Details of how costs are allocated to each tariff and/or Excluded Service Charge;
        Details of the actual costs allocated to each tariff and/or Excluded Service Charge;
        Information that allows a direct comparison between the Tariff Reports and a
        single consumer’s actual bill.
The ESC must therefore require a higher level of disclosure from the DBs in the next
regulatory period in relation to excluded service charges, particularly those relating to the
roll out of interval meters..




                                                                                            49
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




6. Demand Management
The need to develop more effective demand management in the electricity market is
widely recognised. This has been confirmed in the Council of Australian Government
(CoAG) Energy Market Review and Ministerial Council for Energy (MCE) energy
market reform agenda. It is beyond doubt that the ESC and the DBs have a key role to
play in ensuring that this development occurs.

This section of the submission provides a very brief overview of some of the key issues
related to features in economic regulatory regime that apply to electricity distributors that
have the effect of impeding demand management. Comment is also made on the
inadequate response by all of the DBS and the ESC in the face of a clear need to facilitate
development of demand management.


6.1.      DM – What is on offer?
There is nothing in any of the DBs’ proposals about Distributed Generation or Energy
Efficiency. The proposals for Demand Management, apart from Citipower and
Powercor’s unspecified proposal to roll-out (mid 20th Century “ripple control”
technology), are all focussed on “negative incentives” and do nothing to assist consumers
respond to “clearer” pricing signals. Some examples below help to show this.

AGLE:

        (p33) Demand forecasts are used in the assessment of network adequacy to
        identify system deficiencies. This leads to investigations into network
        solutions and non-network solutions (such as demand management). The
        demand forecasts are one of the main drivers for AGLE’s five-year network
        strategic capital expenditure plan.

This is the comment on demand management in AGL’s proposal and is clearly a ‘Do
Nothing’ approach.

SPI Networks (TXU):

        (p72: s7.3.2.5) During the 2006-2010 regulatory period, demand side
        management initiatives will continue to be encouraged where there is an
        efficient opportunity to avoid expensive reinforcement expenditure. SPI
        Networks do not expect the potentially more sophisticated pricing and
        demand management approaches that would be supported by the interval
        meter rollout to impact on network reinforcement capital in the 2006-2010
        regulatory period.

        (And p146) SPI Networks agrees that the current approach to price
        controls does not prevent distribution businesses from facilitating demand
        side responses. SPI Networks has utilised the current price controls to
        establish a range of tariffs that address demand management. Examples of
        these initiatives are: (SPIN here lists 5 network tariffs that supposedly
        "incentivise" DM).


                                                                                           50
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        NEE23 – applies to small domestic photovoltaic installations. This tariff
        offsets energy produced by the photoelectric cell at the same rate as the
        network charge and gives an explicit payment for generation into the grid
        over the summer period when local demands drive transmission charges.

SPI Networks is also proposing a generally ‘Do Nothing’ approach – and anticipating that
it will see no benefits from DM response.

But the ESC should take note that, when the NEE23 Tariff was first introduced, TXU
claimed that it delivered a benefit to Solar PV users. This is clearly incorrect. The
NEE23 tariff is clearly intended to impose substantially higher costs on a small grid-
connected generator than previous tariffs (the Residential Single Rate tariff (NEE11)) by:
        substantially increasing the Standing Charge (by 195%);
        increasing Peak energy charges (by 12.8%); and
        discounting the payment for excess generation during summer peak periods (by
        6.9%).

These sorts of tariff initiatives can only have the effect of reducing incentives for
consumers to pursue and offer demand management. This is not a new issue. The ESC
was advised of this situation by CUAC in September 2003.90 It is very disappointing that
the ESC failed to respond to the consumer-sponsored submission made that identified this
unsatisfactory approach by TXU.

Powercor/CitiPower:

        (p18 (repeated p126)) … new distribution tariffs will be assigned to
        customers when an interval meter is installed. Over the period 2006-10
        these new distribution tariffs will be adjusted to provide stronger demand
        management signals to customers.

        Demand management signals are to be provided by the development of an
        excess reactive demand charge to be applied to large customers exhibiting
        poor power factor;

        (And p96): As the accelerated interval meter rollout only begins to ramp up
        from 2008, there will be minimal reinforcement savings arising during this
        regulatory period. Substantial opportunities may be available in subsequent
        regulatory periods depending on customer interest and retailer behaviour.
        However, this regulatory period represents a one off opportunity to install a
        system capable of significantly reducing future network capital investment at
        a substantially reduced cost.

        Installation of ripple control to those customers receiving interval meters
        over this regulatory period will require $25M. ($17M for CitiPower)

        (And p128): The tariff structure is also important for sending signals about
        the value of demand management to customers. Higher prices can

90
      See p25, Customer Impacts of 2001 Electricity Distribution Price Review - Report to the Consumer
Utility Advocacy Centre from Customer Energy Coalition, Pareto Associates Pty Ltd, September 2003.



                                                                                                    51
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        encourage customers to reduce their demand which can in turn deliver
        positive environmental outcomes.

        (And p129): D1 - Small Single Rate. D1 is the basic single rate residential
        tariff that includes a standing and energy charge. The energy charge includes
        a 4 part inclining block structure that acts as a positive rudimentary demand
        management signal to high energy users. (Similar statement for Small
        Business Tariff)

        (And p134): However, during the next regulatory period it is intended that
        the interval meter tariffs be amended to include sharper demand
        management signals to customers.

        (And p136): As new load management technologies such as ripple control
        (see Section 6.6.8) are deployed in the Powercor Australia distribution
        system, new tariffs that allow these technologies to achieve their intended
        demand management benefits will be introduced as appropriate.

Both CitiPower and Powercor are proposing to contemplate ‘sharper’ price signals for
consumers (that is, impose higher costs on high cost consumers), but at least they are also
proposing to do something that is intended to ameliorate the impact of ‘sharper’ prices by
a limited roll-out of antiquated mid-20th Century ripple control technology.91


6.2.      EUAA Demand Side Response Facility Trial
The Demand Side Response (DSR) Facility Trial92 undertaken by the EUAA during
November and December 200293 clearly demonstrated that coordinated demand
management has potential to deliver significant commercial and economic benefits for
both energy users and electricity distributors (and retailers). Scenarios tested in the Trial
were designed to be as realistic as possible and specifically included targeting of typical
distribution network constraints94 that could be relieved by coordinated, locationally-
specific demand response.

However, the Trial also demonstrated that a number of constraints existed that inhibit
take-up of demand management by end users, distributors and retailers. Major
impediments to demand management identified in the Trial were:
        the need for a coordination function that was capable of ensuring delivering of
        reliable and predictable demand side response capacity;

91
      As noted below and elsewhere in this submission, the submission does not necessarily support
CitiPower/Powercor’s proposal to roll-out ripple control technology. However, the submission very strongly
supports the investigation of this and other more sophisticated load control technologies that could be rolled-
out by distributors. Without sophisticated, low-cost and easy to use load control functionality, consumers
have no real prospect of avoiding much higher electricity bills – and Victoria has little prospect of activating
effective demand management amongst small consumers.
92
      The Trial was based on testing a prototype DSR Facility that provided a coordination, despatch and
settlement clearing function. The DSR Facility operator received offers for physical demand response
capacity linked to ‘buy and sell’ bid conditions.
93
    See: Trial of a Demand Side Response Facility for the National Electricity Market: Independent
Consultant's Report, EUAA and Pareto Associates Pty Ltd, April 2004.
94
     AGL Networks and United Energy participated in the Trial as Victorian distributors.



                                                                                                             52
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        the need to increase the understanding amongst end users of the opportunities for
        demand side response and the potential commercial benefits it could deliver; and
        the need to align the economic and commercial incentives (and signals) in the
        energy market, network and end user sectors.

The Trial was based on testing the effectiveness of a prototype DSR Facility that was
capable of providing the coordination function, thereby addressing the first impediment.
A key objective of the Trial was to encourage participation by its members, provide a
valuable learning process for EUAA members and end-users generally, thereby
addressing the second impediment.

Other impediments were identified by the active and positive participation of large end
users, energy retailers and distributors in NSW, Victoria and South Australia and these
have been discussed with Governments and regulators across the NEM. Key issues that
related to the distribution sector were the basis for estimating the value of DSR in the
network services sectors and the explanations provided by distributors for the value of
and reasons for there bids.

Subsequent to the Trail, action has been initiated by Energy Response Pty Ltd to pursue
commercialisation of the prototype DSR Facility tested in the Trial; and the EUAA has
introduced a structured program to assist its members and other energy users identify and
implement demand response opportunities.

Areas requiring close consideration by the economic regulators, including the ESC, were
identified in two of the key recommendations of the Trial report. A brief comment on the
relevance of these recommendations to the current review is outline below.


6.2.1. Consumers want the positive incentives for action that DBs
       enjoy.

The first Trial report recommendation that is directly relevant to the ESC’s review is to:

        Ensure all stakeholders understand that end-users respond best to ‘positive’
        incentives. The Trial confirmed that commercial incentives are as important
        to end-users as they are to retailers and distributors. End-users made it
        clear that they will not provide DSR if it is not profitable to do so. The
        importance of this observation does not seem to be fully understood by all
        stakeholders.95

The Trial involved large industrial and commercial energy users, but the responses and
views of these users are not likely to be significantly different to small consumers.

The fact that neither DBs nor the ESC understand the importance of this observation is
amply demonstrated in the DBs’ proposals and the ESC’s Papers. For example, the only
references to demand management in the DBs’ proposals to the ESC relate to imposition
of costs onto consumers (who cause the costs). This is not unreasonable, but the Trial
showed that it is not the only way, or even the best way, to stimulate demand response.


95
     p(viii), Op Cit.



                                                                                             53
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




The ESC appears to consider the same course of action as the only one that is realistic.
For example, the ESC proposes to extend the criteria for tariff design by adding a
condition “that tariffs should signal the impact of additional (peak) usage on future
investment costs”. But, on the other hand, the ESC has rejected consideration of
examining or implementing any form of automatic load-management functionality that
would make it easier for consumers to respond to price signals and (potentially) benefit
from implementation of a commercial DSR Facility.


6.2.2. DBs need clearer incentives to pursue demand management

The second Trial report recommendation that is directly relevant to the ESC’s review is
to:

        Clarify incentives for network service providers to pursue DSR. .96

The Trial demonstrated that regulatory incentives affect the way network service
providers value DSR. Analysis following the Trial also confirmed that regulatory
arrangements allow network service providers to manage physical supply risk through a
very different mechanism to that used by retailers to manage risk in the energy market.
The way in which regulatory incentives motivate network services and the discretion they
are permitted in the management of physical supply risk can lead distributors to assign
lower value to DSR than retailers, even though many of the economic fundamentals of
electricity supply are basically the same for the energy and network sectors.

The ‘network’ test scenarios in the Trial confirmed the prototype facility could be used to
provide ‘network’ DSR. However, each distributor submitted bids of substantially
different value for circumstances that were defined as identical in the relevant test
scenarios. This outcome led to considerable discussion amongst Trial participants about
the distributors’ pricing methodologies. While there were some similarities in
methodologies adopted by each distributor, all distributors were clearly influenced by
regulatory incentives and interpreted these differently.

For example, United Energy incorporated ‘standardised’ network reinforcement cost
estimates prepared by United’s consultants, temperature impact on network loading and
the ‘efficiency carry-over’ mechanism in the Victorian regulatory regime. The focus of
United’s pricing methodology was strongly influenced by the details of the Victorian
regulatory framework rather than purely commercial considerations.

A further example was provided in the Trial report. This was based on detailed
information published in the Annual Electricity System Development Review Reports97
required under the NSW Demand Management for Electricity Distributors – Code of
Practice (the NSW DM Code). The example showed how that value of DSR capacity
(expressed in $/MWh), as seen by an electricity distributor, changes from a very high
level as peak demand approaches the capacity of a major distribution transformer to zero
as soon as the transformer capacity is augmented.98 The example also shows that even if

96
     p(vix), Op Cit.
97
      The information contained in the NSW distributors’ planning reports is much the same as that contained
in similar reports published by each of the Victorian distributors.
98
     See Section 4.2.2, p49 and Appendix G, Op Cit.



                                                                                                          54
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




DSR capacity can be coordinated and despatched in sufficient capacity to defer
augmentation, the value of each additional increment of DSR capacity drops substantially
as the total DSR capacity required increases. The decreases in value obviously provide
much reduced incentive for consumers to offer DSR capacity, or even to consider
investing in such capacity.

This outcome reflects the fact that the distributor is able to recover the full cost of any
investment in network augmentation once the investment occurs; and the increment of
capacity that is (normally) added will also provide significant additional network capacity
above the prevailing load levels. Once additional network capacity is added, the
distributor has a commercial incentive to ‘sell’ more network capacity – not ‘buy’
demand management capacity. On the other hand, consumers have no continuing (or
equivalent) incentive to invest in DSR capacity – and would be commercially unwise to
make such investment unless they were able to derive some value other than the
transitory value of the DSR capacity to the distributor.


6.3.      Distributed Generation
Distributed (or embedded) generation may be seen as a particular form of DM and also
suffers from some of the same impediments. It also offers a number of significant and
similar benefits in terms of this review.

The Energy Networks Association argues (in its comment on the ESC's draft decision on
a Victoria-specific Embedded Generation Guideline) that:99

        “With the Weighted Average Price Cap form of regulation in place in
        Victoria and shortly to be established in NSW, there is a direct and
        asymmetric revenue risk associated with an embedded generator. There is
        also the risk of asset stranding, which is also asymmetric. The asymmetric
        nature of these risks means that they cannot be adequately dealt with under
        the Capital Asset Pricing Model currently used to determine the Weighted
        Average Cost of Capital.”

Issues associated with investment risk facing DBs were not dealt with in the ESC's final
Decision on the Embedded Generation (EG) Guideline. It is hoped the ESC would
dismiss the arguments presented by ENA out of hand. However, the ESC has previously
ignored the logic of arguments that EG (particularly "small" EG) is no different to energy
efficiency - as far as the consumer is concerned.100

The revenue risk and risk symmetry of energy efficiency (EE) and EG are identical.
These risks are real in the sense that any decision by a consumer to reduce consumption
results in lower revenue to all segments of the electricity supply industry in the short
term. However, whatever downside EG/EE present to DBs is overwhelmed by the upside
in overall demand and consumption growth – and countered in the longer-term by more
efficient investment in supply infrastructure.

99
     p 3, Submission to the Essential Services Commission Guideline for Embedded Generation - Response
to Draft Decision, Energy Networks Association, May 2004
100
      Provided the EG doesn't cause any more perturbations on the network than (say) changing to high-
efficiency lighting, or stocking the consumers' premises with energy efficient appliances.



                                                                                                    55
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




The ESC's EG Guideline still focuses on the supply side by leaving in place relatively
complex "market-based" remedies (favouring negotiated outcomes, but failing to respond
to the fact that users have neither information or experience to negotiate and are at the
mercy of a monopoly network business in such situations, even if they are large users)
and offering only mild "carrots" to users (in the form of generic, “standard” supply-side
proposed terms and conditions for connection and use of DG).

This ‘blind faith’ in market solutions in the face of overwhelming evidence (provided by
consumers) that market failure exists is also very disappointing.

The ESC is strongly urged to take a more pragmatic approach that seeks to make it as
easy as possible for small embedded generators to be deployed and connected to the
distribution networks101 and provide guidelines with ‘some teeth’ that will have the effect
of assisting larger users efficiently negotiate fair and reasonable connection agreements
with distributors.


6.4.      Approaches to providing incentives for demand
          management
The ESC would do well to follow the example of other, more progressive and consumer-
focussed, regulators such as IPART and ESCoSA on this issue.

IPART recognised the role of DM in relieving network congestion and improving the
utilisation of network assets, both of which would reduce upward pressure on costs many
years ago. It has taken a pro-active stance on DM in its latest Determination and
introduced a number of incentives to promote network DM.102 These include the
introduction of a ‘D-factor’ to the weighted average price cap formula, to recover costs
and revenue foregone arising from DM programs, up to a maximum value equal to the
avoided distribution costs.

IPART also set up a Network DM Consultation Working Group, comprising members
from distributors, Government, industry and user/consumer groups to develop guidelines
for distributors on various aspects DM.103 The group has now completed this role and
IPART has recently published its final guidelines.

A document entitled “DM for Electricity Distributors Code of Practice” (“the NSW DM
Code”) has also been prepared and published for use by the NSW distributors. The DM



101
     A recent submission to the ESC by the Alternative Technology Association (ATA) makes firm
recommendations that would achieve this outcome (See: Impediments to Grid Connection of Solar
Photovoltaic: the consumer perspective, ATA and Marsden Jacob Associates, April 2005). Essentially, the
ATA argues that small embedded generators should be treated on the much the same basis as other forms of
energy efficiency. Small embedded generator owners should be:
• permitted to stay on ‘standard’ Residential or Small Business tariffs;
• required only to ensure their installations comply with existing electrical safety standards;
• required only to advise their retailer that the system has been installed and connected to the distribution
    network; and
• permitted to accept a better offer than ‘standard’ tariffs if and when retailers develop such products.
102
      Determination of NSW Network Prices for the 2004/05 to 2008/09 Period, IPART, June 2004.
103
      The Energy Action Group and EUAA are members of the IPART DM Group.



                                                                                                          56
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Code provides an additional impetus to DM at the distribution level and has recently been
reviewed and improved.

The ESC is urge to examine IPART’s programs for implementation in Victoria.

In addition, in its final determination for ETSA Utilities distribution network in South
Australia, ESCoSA has provided some incentives for DM in the form of adopting a DM
Code that is similar to that adopted by IPART and allowed specific provision for ETSA
Utilities to commit approximately $20 million over the five year regulatory period to trial
a number of demand management initiatives which may result in less need for peak-
driven network expansion.

The range of initiatives to be trialled by ETSA Utilities include:
        “power factor” improvements in business and manufacturing premises;
        trials of Voluntary Load Curtailment (VLC) programmes for large customers;
        Direct Load Control (DLC) of domestic equipment such as air-conditioners and
        pool pumps;
        use of standby generation, and
        the use of incentives for customers to reduce demand at times of peak demand.104

These actions by IPART and ESCoSA shows that the ESC needs to provide some
additional ‘positive’ incentives for DM as part of the next regulatory period. If it does not
do this, the ESC leaves itself open to the accusation that it is out-of-touch with the latest
developments in regulation, out-of-step with other regulators and out of touch with
actions that could assist in protecting the long-term interests of consumers. Victoria,
which badly needs a more active DM response to help it meet the challenge of growing
peak demand, will be left more exposed to the consequences, including unfettered growth
in peak demand, higher Capex and higher electricity costs.

The ESC’s proposals are, so far, also totally inadequate. The ESC said in the Issues
Paper that it was “interested in clarifying the barriers in the Commission’s regulatory
framework that may exist to demand side responses. Where barriers relate directly to the
regulatory framework, the Commission intends to address these for the next regulatory
period.”105 But the proposals in the Position Paper appear to be no more than reliance
on:
        “adjustment of the DRR (demand related reinforcement) capital expenditure based
        on energy consumption (providing) distributors with greater incentive to maintain
        or improve their load profiles - since increased DRR capital expenditure caused by
        worsening profiles would impact the distributors’ efficiency carryover amount;106




104
    See p(v) and pp54-60, 2005 - 2010 Electricity Distribution Price Determination, Part A - Statement Of
Reasons, Essential Services Commission of South Australia, April 2005.
105
      p183, ESC Issues Paper.
106
      p87, ESC Position Paper.



                                                                                                       57
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




        not … constrain the distributors from adjusting their tariff structures in light of
        information obtained through the interval meter rollout and to pursue demand-side
        management objectives.107

The only mentions of positive incentives for demand management and embedded
generation in the ESC Position Paper are in the context of allowing exclusions from the
S-Factor (where an embedded generator can be linked to a supply outage)108 and energy
efficiency and energy conservation rate no mention at all.

This is a very poor and totally inadequate regulatory response from the ESC to these
important issues. It is disappointing that the ESC appears to be intransigent on this key
issue and/or fails to understand the obstacles to DM in relation to networks.

The ESC needs to show clearly how its approach will facilitate DM during the next
regulatory period and to what extent. The ESC has made the point during this review that
it believes the current regime already provides sufficient incentives for DM to occur
where “it is economic”. But the ESC unfortunately fails to understand the drivers behind
DM and the impediments it faces. These include its still nascent state in the NEM,
cultural barriers in DB and among customers and a lack of information and awareness
about its opportunities.109

Whilst it is acknowledged that the ESC cannot overcome all these hurdles in this review,
it can be far more positive in support of DM than has been indicated to date. The ESC
also needs to show why the application of positive incentives, including those provided
by other regulators, are not suitable and the reasons for this. It should demonstrate this
with facts and figures not mere assertions.




107
      p183, ESC Position Paper.
108
      p117-120, ESC Position Paper.
109
      The EUAA DSR Trail clearly showed this to be the case.



                                                                                         58
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




Appendix A: DB Capex and Opex
Performance

                          Total CAPEX ($M Jun04 - With & w/o Metering)
                     AGLE DB Forecast
   $250
                     AGLE Excl Metering
                     AGLE ORG
   $200              AGLE Actual
                     Linear (AGLE Actual)


   $150



   $100



    $50



     $0
          96

                97

                      98

                            99

                                   00

                                           01

                                                  02

                                                        03

                                                              04

                                                                    05

                                                                          06

                                                                                07

                                                                                      08

                                                                                            09

                                                                                                  10
      19

               19

                     19

                           19

                                  20

                                        20

                                                 20

                                                       20

                                                             20

                                                                   20

                                                                         20

                                                                               20

                                                                                     20

                                                                                           20

                                                                                                 20
                            FIGURE A.1 AGLE CAPEX PERFORMANCE




                          Total CAPEX ($M Jun04 - With & w/o Metering)
                     CPL DB Forecast
   $250
                     CPL Excl Metering
                     CPL ORG
   $200              CPL Actual
                     Linear (CPL Actual)


   $150



   $100



    $50



     $0
          96

                97

                      98

                            99

                                   00

                                           01

                                                  02

                                                        03

                                                              04

                                                                    05

                                                                          06

                                                                                07

                                                                                      08

                                                                                            09

                                                                                                  10
      19

               19

                     19

                           19

                                  20

                                        20

                                                 20

                                                       20

                                                             20

                                                                   20

                                                                         20

                                                                               20

                                                                                     20

                                                                                           20

                                                                                                 20




                          FIGURE A.2 CITIPOWER CAPEX PERFORMANCE




                                                                                                       59
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




                           Total CAPEX ($M Jun04 - With & w/o Metering)
                      PCL DB Forecast
   $250
                      PCL Excl Metering
                      PCL ORG
   $200               PCL Actual
                      Linear (PCL Actual)


   $150



   $100



    $50



      $0
           96

                 97

                       98

                             99

                                      00

                                            01

                                                  02

                                                        03

                                                              04

                                                                    05

                                                                          06

                                                                                07

                                                                                      08

                                                                                            09

                                                                                                  10
       19

                19

                      19

                            19

                                   20

                                           20

                                                 20

                                                       20

                                                             20

                                                                   20

                                                                         20

                                                                               20

                                                                                     20

                                                                                           20

                                                                                                 20
                           FIGURE A.3 POWERCOR CAPEX PERFORMANCE




                           Total CAPEX ($M Jun04 - With & w/o Metering)
                     SPI/TXU DB Forecast
   $250
                     SPI/TXU Excl Metering
                     SPI/TXU ORG
   $200              SPI/TXU Actual
                     Linear (SPI/TXU Actual)


   $150



   $100



    $50



     $0
           96

                 97

                       98

                             99

                                    00

                                            01

                                                  02

                                                        03

                                                              04

                                                                    05

                                                                          06

                                                                                07

                                                                                      08

                                                                                            09

                                                                                                  10
      19

                19

                      19

                            19

                                   20

                                           20

                                                 20

                                                       20

                                                             20

                                                                   20

                                                                         20

                                                                               20

                                                                                     20

                                                                                           20

                                                                                                 20




                            FIGURE A.4 TXU/SPI CAPEX PERFORMANCE
Note: We have not examined TXU’s submission in sufficient detail to understand why the Capex
forecast excluding metering appears to be much lower than actual Capex for the current regulatory
period.




                                                                                                       60
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




                           Total CAPEX ($M Jun04 - With & w/o Metering)
                      UEL DB Forecast
   $250
                      UEL Excl Metering
                      UEL ORG
   $200               UEL Actual
                      Linear (UEL Actual)


   $150



   $100



    $50



      $0
           96

                 97

                       98

                             99

                                    00

                                            01

                                                  02

                                                        03

                                                              04

                                                                    05

                                                                          06

                                                                                07

                                                                                      08

                                                                                            09

                                                                                                  10
       19

                19

                      19

                            19

                                   20

                                         20

                                                 20

                                                       20

                                                             20

                                                                   20

                                                                         20

                                                                               20

                                                                                     20

                                                                                           20

                                                                                                 20
                      FIGURE A.5 UNITED ENERGY CAPEX PERFORMANCE




                                                                                                       61
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




                           Total O&M ($M Jun04 - With & w/o Metering)

  $150
                           AGLE DB Forecast
                           AGLE Excl Metering
  $125
                           AGLE ORG
                           AGLE Actual
  $100                     Linear (AGLE Actual)


    $75


    $50


    $25


     $0
          96

                97

                      98

                             99

                                   00

                                         01

                                                 02

                                                       03

                                                             04

                                                                   05

                                                                         06

                                                                               07

                                                                                     08

                                                                                              09

                                                                                                    10
      19

               19

                     19

                           19

                                  20

                                        20

                                              20

                                                      20

                                                            20

                                                                  20

                                                                        20

                                                                              20

                                                                                    20

                                                                                          20

                                                                                                   20
                             FIGURE A.6 AGLE OPEX PERFORMANCE




                             Total O&M ($M Jun04 - With & w/o Metering)
  $150
                      CPL DB Forecast
                      CPL Excl Metering
  $125                CPL ORG
                      CPL Actual
  $100                Linear (CPL Actual)


   $75


   $50


   $25


    $0
         96

                97

                      98

                             99

                                   00

                                         01

                                                 02

                                                       03

                                                             04

                                                                   05

                                                                         06

                                                                               07

                                                                                         08

                                                                                               09

                                                                                                        10
     19

               19

                     19

                           19

                                  20

                                        20

                                              20

                                                      20

                                                            20

                                                                  20

                                                                        20

                                                                              20

                                                                                     20

                                                                                              20

                                                                                                    20




                           FIGURE A.7 CITIPOWER OPEX PERFORMANCE




                                                                                                             62
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




                              Total O&M ($M Jun04 - With & w/o Metering)
  $150


  $125


  $100


   $75
                    PCL DB Forecast
                    PCL Excl Metering
   $50              PCL ORG
                    PCL Actual
   $25              Linear (PCL Actual)


    $0
         1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010



                           FIGURE A.8 POWERCOR OPEX PERFORMANCE




                          Total O&M ($M Jun04 - With & w/o Metering)
 $150


 $125


 $100


  $75                   SPI/TXU DB Forecast
                        SPI/TXU Excl Metering
  $50                   SPI/TXU ORG
                        SPI/TXU Actual
                        Linear (SPI/TXU Actual)
  $25


   $0
        96

              97

                    98

                           99

                                 00

                                         01

                                               02

                                                     03

                                                           04

                                                                 05

                                                                       06

                                                                             07

                                                                                   08

                                                                                         09

                                                                                               10
    19

             19

                   19

                         19

                                20

                                      20

                                              20

                                                    20

                                                          20

                                                                20

                                                                      20

                                                                            20

                                                                                  20

                                                                                        20

                                                                                              20




                            FIGURE A.9 TXU/SPI OPEX PERFORMANCE




                                                                                                    63
Victorian Consumers’ Groups
VIC 2006 Electricity Distribution Price Review




                          Total O&M ($M Jun04 - With & w/o Metering)
 $150


 $125


 $100


  $75                     UEL DB Forecast
                          UEL Excl Metering

  $50                     UEL ORG
                          UEL Actual
                          Linear (UEL Actual)
  $25


    $0
         96

               97

                     98

                           99

                                  00

                                        01

                                                 02

                                                       03

                                                             04

                                                                   05

                                                                         06

                                                                               07

                                                                                     08

                                                                                           09

                                                                                                 10
     19

              19

                    19

                          19

                                20

                                       20

                                              20

                                                      20

                                                            20

                                                                  20

                                                                        20

                                                                              20

                                                                                    20

                                                                                          20

                                                                                                20
                     FIGURE A.10 UNITED ENERGY OPEX PERFORMANCE




                                                                                                      64
      Victorian Consumers’ Groups
      VIC 2006 Electricity Distribution Price Review




      Appendix B: WACC Comparisons

Industry-Jurisdiction                   Regulatory Decision                                            WACC PARAMETER
                                                                              Cost of debt     MRP     Equity     Post-tax RoE      Post-tax WACC
                                                                                                        beta                           (Vanilla)
                                                                            Nom         Real   Nom               Nom       Real    Nom       Real
ELECTRICITY - AUS          IPART 1999 ED (Mid)                (Mid)         7.50%      4.37%   5.50%   0.960    12.00%     8.64%   9.30%     6.08%
                          SA EPO 1999 ED (Mid)                (Mid)         6.76%      4.15%   6.50%   1.015    12.24%     9.00%   9.23%     6.52%
                          ACCC 2000 ETN (Mid)           Transgrid (Mid)     7.81%      4.52%   6.00%   1.015    12.88%     9.43%   9.84%     6.49%
                              ORG 2000 ED                                   7.73%      5.00%   6.00%   1.000    12.19%     9.50%   9.51%     6.80%
                              QCA 2000 ED                                   7.01%      4.83%   6.00%   0.710    9.62%      7.39%   8.05%     5.85%
                             ACCC 2001 ETQ                 PowerLink        6.85%      4.43%   6.00%   1.000    11.80%     9.12%   8.83%     6.30%
                             ACCC 2002 ETS               Electranet SA      6.39%      4.23%   6.00%   1.000    11.17%     8.92%   8.30%     6.11%
                             ACCC 2002 ETV                   SPI            6.32%      4.19%   6.00%   1.000    11.09%     8.90%   8.23%     6.08%
                                                       PowerNet/VENCOR
                              OTER 2003 ED                                  6.30%      4.12%   6.00%   0.950    10.75%     8.48%   8.08%     5.87%
                             ACCC 2003 ETT                 Transend         6.77%      4.35%   6.00%   1.000    11.84%     9.32%   8.80%     6.34%
                              ICRC 2004 ED                                  6.80%      4.53%   6.00%   0.900    11.10%     8.66%   8.52%     6.18%
                             ACCC 2004 ETN              TransGrid (Draft)   6.76%      4.22%   6.00%   1.000    11.87%     9.22%   8.80%     6.22%
                           IPART 2004 ED (Mid)                (Mid)         7.00%      4.39%   5.50%   0.945    11.20%     8.39%   8.68%     5.99%
                              ERA 2005 ED                    (Draft)        6.45%      3.80%   6.00%   1.000    11.33%     8.56%   8.40%     5.71%
                            ESCoSA 2005 ED                                  7.40%      4.90%   6.00%   0.800    10.60%     8.00%   8.68%     6.13%
                              QCA 2005 ED                                   6.83%      3.96%   6.00%   0.900    11.01%     8.03%   8.50%     5.59%
GAS - AUS                 IPART 1997 GD (Mid)                 (Mid)         9.00%      6.34%   7.00%   0.740    10.88%    10.22%   9.94%     8.28%
                             ACCC 1998 GTV                    TPA           7.20%      4.60%   6.00%   1.200    13.20%    10.40%   9.60%     6.94%
                              ORG 1998 GD                                   7.20%      4.59%   6.00%   1.200    13.20%    10.40%   9.60%     6.93%
                            OFFGAR 2000 GD                                  7.47%      4.56%   6.00%   1.080    12.70%     9.70%   9.60%     6.60%
                          IPART 2000 GD (Mid)                 (Mid)         7.44%      4.48%   5.50%   1.000    12.00%     8.86%   9.26%     6.23%
                              QCA 2001 GD                                   7.51%      4.89%   6.00%   0.990    11.90%     9.17%   9.27%     6.60%
                              ESC 2002 GD                                   7.40%      5.09%   6.00%   1.000    11.80%     9.40%   9.16%     6.80%
                             ACCC 2002 GTV                  GasNet          6.90%      4.63%   6.00%   1.000    11.15%     8.80%   8.60%     6.30%
                            OFFGAR 2003 GT               EPIC DBNGP         6.48%      4.14%   6.00%   1.200    12.48%    10.00%   8.88%     6.48%
                           ICRC 2004 GD (Mid)                 (Mid)         6.75%      4.08%   6.00%   0.995    11.38%     8.59%   8.60%     5.88%
                          IPART 2004 GD (Mid)              (Mid-Draft)      6.55%      3.95%   6.00%   0.900    10.85%     8.10%   8.27%     5.61%



      VIC 2006 EDPR Joint Consumer Submission - FINALv2 / 16 May 2005                                                                                65
      Victorian Consumers’ Groups
      VIC 2006 Electricity Distribution Price Review




Industry-Jurisdiction                   Regulatory Decision                                                  WACC PARAMETER
                                                                              Cost of debt        MRP        Equity         Post-tax RoE      Post-tax WACC
                                                                                                              beta                               (Vanilla)
                                                                            Nom         Real      Nom                     Nom        Real    Nom       Real
WATER -AUS               IPART 2000 W&S (Mid)                 (Mid)         7.30%      4.39%     5.50%        0.835      11.10%      7.99%   8.82%     5.83%
                          GPOC 2001 BW (Mid)                  (Mid)         6.44%      4.07%     6.00%        0.773      10.37%      7.91%   8.41%     5.99%
                              QCA 2003 RW                  Burdekin         7.97%      5.34%     6.00%        0.400       8.57%      5.92%   8.27%     5.63%
                         IPART 2003 W&S (Mid)                 (Mid)         5.95%      3.67%     5.50%        0.775       9.45%      7.01%   7.35%     5.00%
                          ICRC 2004 W&S (Mid)                 (Mid)         6.87%      4.60%     6.00%        0.900      11.02%      8.66%   8.53%     6.22%
                           GPOC 2004 W (Mid)                  (Mid)         6.23%      4.00%     6.00%        0.773      10.17%      7.86%   8.20%     5.93%
                             QCA 2004 W&S                  Gladstone        6.77%      4.17%     6.00%        0.640       9.25%      6.59%   8.02%     5.38%
                             ESC 2005 W&S                    (Draft)        6.31%      3.71%     6.00%        0.750       9.71%      7.03%   7.67%     5.10%
OTHER - AUS               IPART 1999 Rail (Mid)               (Mid)         6.37%      4.50%     5.50%        0.850      10.06%      8.11%   8.03%     6.12%
                             QCA 2004 Ports                Dalrymple        7.14%      4.45%     6.00%        0.660       9.80%      7.04%   8.20%     5.48%


ELEC - UK                 OFFER 1994 ED (Mid)                 (Mid)         5.98%      3.90%     3.75%        0.550       7.46%      5.35%   7.30%     5.20%
                              UKCC 1994 ED             (SHE Appeal - Mid)   6.23%      4.15%     4.00%        0.575       8.11%      5.99%   7.96%     5.84%
                             OFGEM 1999 ED                                  6.86%      4.30%     3.50%        1.000       8.56%      6.00%   7.71%     5.11%
                             OFGEM 2000 ET                    NGC           7.02%      4.45%     3.50%        1.000       8.82%      6.25%   7.74%     5.14%
                             OFGEM 2004 ED                                  7.22%      4.10%     3.50%        0.800       8.50%      7.50%   7.77%     5.50%
GAS - UK                   OFGEM 2001 GT&D                  Transco         7.02%      4.45%     3.50%        1.000       8.82%      6.25%   7.69%     5.09%
WATER - UK                  OFWAT 1994 W&S                    (Mid)                    4.50%     3.00%                               6.00%             5.50%
                         OFWAT 1999 W&S (Mid)          Large W&SC (Mid)     7.37%      4.50%     3.50%        0.750       8.20%      5.30%   7.79%     4.75%
                         OFWAT 2004 W&S (Mid)                 (Mid)         6.89%      3.85%     4.50%        1.000      10.39%      7.25%   8.47%     4.75%
      Notes:
                Figures shown in red italic font have been estimated using parameter values taken from regulators’ decisions.
                Figures shown in bold font are parameters/WACC values adopted in regulators’ decisions.
                Figures shown in normal font are parameters/WACC values quoted in regulators’ decisions.
                Where regulators quote ranges for parameter values, a mid-point value has been used.




      VIC 2006 EDPR Joint Consumer Submission - FINALv2 / 16 May 2005                                                                                          66

				
DOCUMENT INFO
Shared By:
Categories:
Stats:
views:5
posted:11/16/2010
language:English
pages:76